System and process for steam cracking and pfo treatment integrating hydrodealkylation and naphtha reforming

ABSTRACT

A process for treatment of PFO from a steam cracking zone includes hydrodealkylating PFO or a portion thereof for conversion of polyaromatics compounds contained in the PFO into hydrodealkylated aromatic compounds with one benzene ring, a hydrodealkylated BTX+ stream. In addition, a naphtha reformer is integrated, so that the hydrodealkylated BTX+ stream and a reformate stream are separated into BTX compounds.

RELATED APPLICATIONS

Not applicable.

BACKGROUND OF THE INVENTION Field of the Invention

The present disclosure concerns integrated processes and systems tomaximize recovery of products including benzene, toluene and xylenes(BTX) from pyrolysis fuel oil (PFO) obtained from a steam cracking unit.

Description of Related Art

Petrochemical refiners are facing issues with utilization of PFO streamsobtained from steam cracking. Such steam cracking processes are wellknown and employ very high temperature, high flow rates and productionof large amounts of flammable gases. The overall process conditions areset to maximize useful and valuable chemicals in the steam crackingeffluent, the most desirable of which are typically light olefins.Useful and valuable products are also typically obtained from LPG andpyrolysis gasoline, commonly referred to as pygas or py-gas.

The heaviest portion of the steam cracking effluents is commonlyreferred to as pyrolysis oil, pyrolysis fuel oil (PFO) stream, py-oil orpyoil, which is a C9+ stream that contains C9+ paraffins, monoaromatics,naphtheno-monoaromatics, diaromatics, naphtheno-diaromatics, andpoly-aromatics.

In steam cracking operations in which ethane or propane are used as thefeedstock, the product is mainly ethene, with other products includingmethane, propene, butadiene, and py-gas, with relatively small quantityof PFO being produced. In steam cracking operations in which naphtha isused as feedstock, in addition to the light olefin products, the yieldsof both py-gas and PFO are relatively higher as compared to ethane orpropane cracking. The PFO from naphtha cracking contains C9+ paraffins,monoaromatics including BTX components, naphtheno-monoaromatics,diaromatics, naphtheno-diaromatics, and to some extent poly-aromaticswith more than three aromatic rings. A typical PFO from steam crackingof naphtha can be further processed conventionally, for example fornaphthalene extraction or for production of carbon black (see Ristic etal., Compositional Characterization of Pyrolysis Fuel Oil from Naphthaand Vacuum Gas Oil, Energy Fuels, 2018, 32 (2), pp 1276-1286). Table 1below shows an example of the chemical compositions of PFO streamsobtained from the steam cracking of naphtha and the steam cracking ofVGO, according to the data disclosed in in Ristic et al., CompositionalCharacterization of Pyrolysis Fuel Oil from Naphtha and Vacuum Gas Oil,Energy & Fuels 32(2)⋅January 2018 (1276-1286), Table 6.

TABLE 1 PFO from naphtha PFO from VGO cracking cracking Compound name(wt %) (wt %) naphthalene 12.5 3.8 1-methylnaphthalene 2.1 2.22-methylnaphthalene 3.7 3.3 acenaphthene 0.4 0.2 acenaphthylene 1.7 1.0fluorene 1.1 1.0 phenanthrene 1.6 1.4 anthracene 0.3 0.4 fluoranthene0.1 0.2 pyrene 0.4 0.3 chrysene 0.1 0.1

In contrast, with steam cracking of heavier feedstocks, the PFO that isproduced contains a much higher quantity of poly-aromatics having threeor more aromatic rings. For instance, in certain embodiments, PFO fromsteam cracking of heavy feedstocks contains at least about 20, 30, 40,50, or 60 wt % of poly-aromatics having three or more aromatic rings.The below Table 2 shows an example of the chemical composition of a PFOstream obtained from hydroprocessing of Arab light crude oil and steamcracking of a fraction having heavy components separated, for instancecut at 540° C., from the hydroprocessed crude oil, for example,according to the process described in U.S. Pat. No. 9,255,230. This PFO,referred to herein as a “refractory” PFO from the steam cracking oftreated crude oil or other treated heavy oil feeds, includes over 40 wt% of poly-aromatics having three or more aromatic rings, which includetriaromatics, naphtheno-triaromatics, tetraaromatics, penta-aromaticsand heavier poly-aromatics including asphaltenes and coke. Theseexcessive quantities of heavier poly-aromatics are uncommon in PFO fromnaphtha steam cracking. In addition to the di-aromatics andtri-aromatics, the PFO also contains tetra-aromatics, penta-aromaticsand heavier poly-aromatics in concentrations that exceed those fromnaphtha steam cracking.

TABLE 2 Compounds wt % Paraffin (C9+) 0.64 Monoaromatics 1.81Naphtheno-monoaromatics 3.2 Diaromatics 20.26 Naphtheno-diaromatics 9.83Triaromatics 9.59 Naphtheno-triaromatics 7.26 Tetraaromatics 5.14Penta-aromatics 2.04 Other heavier polyaromatics 40.23 Total 100

Typically, the PFO stream is a rejected stream at the bottom of thesteam cracking effluent separator. The PFO stream contains variouspoly-aromatics including styrene, naphthene, anthracene, bi-phenyl, andalso having poly-aromatics with three or more aromatic in higherconcentrations in refractory PFO compared to PFO obtained from naphthacracking. Conventionally, PFO streams from naphtha cracking and alsofrom cracking of heavier feeds are used and/or valued as fuel oilblending components. For instance, in economic evaluations, PFO isvalued as a low sulfur fuel oil stream, which is a considerable discountcompared to aromatic hydrocarbons including benzene, toluene and mixedxylenes (BTX), or benzene, toluene, ethylbenzene and mixed xylenes(BTEX).

Therefore, a need exists for improved processes and systems fortreatment of PFO streams to maximize recovery of BTX or BTEX compounds.

SUMMARY OF THE INVENTION

The above objects and further advantages are provided by the system andprocess for treatment of refractory PFO from steam cracking of treatedcrude oil or other treated heavy oil feeds, which comprises at least 40wt % of polyaromatics having three or more aromatic rings includingtriaromatics, naphtheno-triaromatics, tetraaromatics, penta-aromaticsand heavier poly-aromatics including asphaltenes and coke.

In certain embodiments, a process for treatment of PFO from a steamcracking zone comprises optionally separating the PFO into at least afirst stream containing C9+ aromatics compounds with one benzene ringand C10+ aromatic compounds, and a second stream containing C20+polyaromatic compounds. All or a portion of the PFO, or all or a portionof the first stream containing C9+ aromatics compounds with one benzenering and C10+ aromatic compounds, are reacted using catalysts andconditions, including hydrogen, effective for conversion ofpolyaromatics compounds contained in the PFO into aromatic compoundswith one benzene ring, selective ring opening, and dealkylation, toproduce reaction effluent including LPG and a hydrodealkylated BTX+stream. LPG is separated from the reaction effluent. A naphtha feed issubjected to catalytic reforming to produce a reformate stream. At leasta portion of the hydrodealkylated BTX+ stream and at least a portion ofthe reformate stream are separated into BTX compounds.

In certain embodiments, a system for treatment of PFO from a steamcracking zone comprises an optional PFO separation zone having one ormore inlets in fluid communication with the steam cracking zone, one ormore outlets for discharging a fraction of the PFO including C9+aromatics compounds with one benzene ring and C10+ aromatic compounds,and one or more outlets for discharging a fraction of the PFO includingcontaining C20+ polyaromatic compounds. A hydrodealkylation zoneincludes one or more inlets in fluid communication with the steamcracking zone to receive PFO or the first outlet of the PFO separationzone to receive C9+ aromatics compounds with one benzene ring and C10+aromatic compounds from the PFO, and hydrogen, and one or more outletsfor discharging reaction effluent including LPG and hydrodealkylatedBTX+ compounds. A separation zone includes one or more inlets in fluidcommunication with the one or more outlets of the hydrodealkylationzone, one or more outlets for discharging LPG, and one or more outletsfor discharging hydrodealkylated BTX+ compounds. A catalytic reformingzone includes one or more inlets in fluid communication with a source ofnaphtha feed and one or more outlets for discharging a reformate stream.A BTX splitting zone includes one or more inlets in fluid communicationwith the one or more outlets of the hydrodealkylation zone fordischarging reaction effluent including hydrodealkylated BTX+ compoundsand the one or more outlets of the catalytic reforming zone fordischarging the reformate stream, and one or more outlets fordischarging BTX compounds.

Still other aspects, embodiments, and advantages of these exemplaryaspects and embodiments, are discussed in detail below. Moreover, it isto be understood that both the foregoing information and the followingdetailed description are merely illustrative examples of various aspectsand embodiments, and are intended to provide an overview or frameworkfor understanding the nature and character of the claimed aspects andembodiments. The accompanying drawings are included to provideillustration and a further understanding of the various aspects andembodiments, and are incorporated in and constitute a part of thisspecification. The drawings, together with the remainder of thespecification, serve to explain principles and operations of thedescribed and claimed aspects and embodiments.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention will be described in further detail below and withreference to the attached drawings, and where:

FIG. 1 is a process flow diagram of an embodiment of an integratedsystem including steam cracking and naphtha reforming, and includingtreatment of light PFO by hydrodealkylation to produce BTX;

FIG. 2 is a process flow diagram of an embodiment of an integratedsystem including steam cracking and naphtha reforming, and includingtreatment of PFO by hydrodealkylation to produce BTX;

FIGS. 3, 4, 5 and 6 schematically depict operations of steam crackingunits integrated with feed pretreatment; and

FIGS. 7, 8 and 9 schematically depict operation of a catalytic reformingzone for production reformate suitable as additional feed for BTXsplitting in the embodiments of FIGS. 1 and 2.

DETAILED DESCRIPTION OF THE INVENTION

The phrase “a major portion” with respect to a particular stream orplural streams means at least about 50 wt % and up to 100 wt %, or thesame values of another specified unit.

The phrase “a significant portion” with respect to a particular streamor plural streams means at least about 75 wt % and up to 100 wt %, orthe same values of another specified unit.

The phrase “a substantial portion” with respect to a particular streamor plural streams means at least about 90, 95, 98 or 99 wt % and up to100 wt %, or the same values of another specified unit.

The phrase “a minor portion” with respect to a particular stream orplural streams means from about 1, 2, 4 or 10 wt %, up to about 20, 30,40 or 50 wt %, or the same values of another specified unit.

The term “crude oil” as used herein refers to petroleum extracted fromgeologic formations in its unrefined form. Crude oil suitable as thesource material for the processes herein include any crude oil producedworldwide. Examples are Arabian Heavy, Arabian Light, Arabian ExtraLight, other Gulf crudes, Brent, North Sea crudes, North and WestAfrican crudes, Indonesian, Chinese crudes, or mixtures thereof. Thecrude petroleum mixtures can be whole range crude oil or topped crudeoil. As used herein, “crude oil” also refers to such mixtures that haveundergone some pre-treatment such as water-oil separation; and/orgas-oil separation; and/or desalting; and/or stabilization. In certainembodiments, crude oil refers to any of such mixtures having an APIgravity (ASTM D287 standard), of greater than or equal to about 10°,20°, 30°, 32°, 34°, 36°, 38°, 40°, 42° or 44°.

The term “C # hydrocarbons” or “C #”, is used herein having itswell-known meaning, that is, wherein “#” is an integer value, and meanshydrocarbons having that value of carbon atoms. The term “C #+hydrocarbons” or “C #+” refers to hydrocarbons having that value or morecarbon atoms. The term “C #− hydrocarbons” or “C #− ” refers tohydrocarbons having that value or less carbon atoms. Similarly, rangesare also set forth, for instance, C1-C3 means a mixture comprising C1,C2 and C3. When “C #”, “C #+” or “C #− ” are used in conjunction with“aromatics” they represent one-ring aromatics, diaromatics and/or otherpolyaromatics having that value of carbon atoms, that value or morecarbon atoms, or that value or less carbon atoms. As used herein indescribing mixed hydrocarbon streams, “C #” is not intended to representa sharp cut-off but rather are used for convenience to describe thecarbon number of a major portion of said stream. For example, a “C5”stream generally contains a major portion of C5 components and a minorportion of C4 and C6 components.

The term “petrochemicals” or “petrochemical products” refers to chemicalproducts derived from crude oil that are not used as fuels.Petrochemical products include olefins and aromatics that are used as abasic feedstock for producing chemicals and polymers. Typical olefinicpetrochemical products include, but are not limited to, ethylene,propylene, butadiene, butylene-1, isobutylene, isoprene, cyclopentadieneand styrene. Typical aromatic petrochemical products include, but arenot limited to, benzene, toluene, xylene, and ethyl benzene.

The term “olefin” is used herein having its well-known meaning, that is,unsaturated hydrocarbons containing at least one carbon-carbon doublebond. In plural, the term “olefins” means a mixture comprising two ormore unsaturated hydrocarbons containing at least one carbon-carbondouble bond. In certain embodiments, the term “olefins” relates to amixture comprising two or more of ethylene, propylene, butadiene,butylene-1, isobutylene, isoprene and cyclopentadiene.

The term “BTX” as used herein refers to the well-known acronym forbenzene, toluene and xylenes.

The acronym “LPG” as used herein refers to the well-known acronym forthe term “liquefied petroleum gas,” and generally is a mixture of C3-C4hydrocarbons. In certain embodiments, these are also referred to as“light ends.”

The term “naphtha” as used herein refers to hydrocarbons boiling in therange of about 20-205, 20-193, 20-190, 20-180, 20-170, 32-205, 32-193,32-190, 32-180, 32-170, 36-205, 36-193, 36-190, 36-180 or 36-170° C.

The term “light naphtha” as used herein refers to hydrocarbons boilingin the range of about 20-110, 20-100, 20-90, 20-88, 32-110, 32-100,32-90, 32-88, 32-80, 36-110, 36-100, 36-90, 36-88 or 36-80° C.

The term “heavy naphtha” as used herein refers to hydrocarbons boilingin the range of about 80-205, 80-193, 80-190, 80-180, 80-170, 88-205,88-193, 88-190, 88-180, 88-170, 90-205, 90-193, 90-190, 90-180, 90-170,93-205, 93-193, 93-190, 93-180, 93-170, 100-205, 100-193, 100-190,100-180, 100-170, 110-205, 110-193, 110-190, 110-180 or 110-170° C.

In certain embodiments naphtha, light naphtha and/or heavy naphtha referto such petroleum fractions obtained by crude oil distillation, ordistillation of intermediate refinery processes as described herein.

The terms “pyrolysis gasoline” and its abbreviated form “py-gas” areused herein having their well-known meaning, that is, thermal crackingproducts generally including aromatic, olefinic and paraffinichydrocarbons in the range of C5s to C9s or even including C10, C11 andeven some C12 hydrocarbons, for instance having an end boiling point inthe range of about 170-210 or 170-215° C.

The terms “pyrolysis oil” and its abbreviated form “py-oil,” and“pyrolysis fuel oil” and its abbreviated form “PFO,” are used hereinhaving their well-known meaning, that is, a heavy oil fraction, C9+,that is derived from steam cracking.

The terms “light pyrolysis oil” and its acronym “LPO” as used herein incertain embodiments refer to pyrolysis oil having an end boiling pointof about 340, 360, 380 or 400° C.

The terms “heavy pyrolysis oil” and its acronym “HPO” as used herein incertain embodiments refer to pyrolysis oil having an initial boilingpoint of about 340, 360, 380 or 400° C.

The terms “reformate” or “chemical reformate” as used herein refer to amixture of hydrocarbons that are rich in aromatics, and are intermediateproducts in the production of chemicals and/or gasoline, and includehydrocarbons boiling in the range of about 30-200, 40-200, 30-185,40-185, 30-170 or 40-170° C.

The embodiments herein include processes and systems that integratesteam cracking with treatment of the PFO obtained from such steamcracking operations. The steam cracking feedstock can be selected from atreated crude oil stream and other treated heavy oil streams such asthose in the atmospheric gas oil range, atmospheric residue range,vacuum gas oil range and/or vacuum residue range. The steam crackingfeed is treated prior to steam cracking by hydroprocessing/hydrotreatingand/or solvent deasphalting. The rejected PFO bottoms stream from thesteam cracking unit contains large amount of polyaromatics (for example,with polyaromatics having an average molecular weight that variesbetween about 150 to 300 kg/kmol and higher), and is conventionallyrecovered as PFO for use as a fuel oil component. In the processdisclosed herein, the PFO obtained from steam cracking of treated crudeoil or other treated heavy oil feed is referred to as “refractory PFO.”This refractory PFO contains a very high amount of polyaromatics, forinstance, at least about 20, 30, 40, 50, or 60 wt % of poly-aromaticshaving three or more aromatic rings, and total poly-aromaticscomposition of at least about 50, 60, 70, 80, 90, or 94 wt %. The PFO isconsidered “refractory” due to its high content of polyaromaticshydrocarbons and heavier molecular weight components.

Refractory PFO is used as feedstock to produce additional BTX/BTEX, andco-produced LPG is recycled to the steam cracking zone as additionalfeed. BTX/BTEX production and refractory PFO treatment are integrated tominimize loss of aromatics to a fuel oil stream and maximize steamcracking feed. Overall operation efficiencies of steam crackingprocesses are increased. By converting the polyaromatics into usefulchemical building blocks BTX/BTEX rather than combusting them as part offuel oil, additional higher value products can be obtained from theintegrated processes and systems herein. Further, co-produced LPG, andin certain embodiments naphtha-range byproducts, serve as additionalsteam cracker feed. These co-produced components can be introducedbefore hydroprocessing of the initial feed, before steam cracking of thehydroprocessed feed, or within the steam cracking. In certainoperations, co-produced LPG, and in certain embodiments naphtha-rangebyproducts components, can pass to a pyrolysis section combined withheated hydroprocessed feed from a convection section of a steam crackingunit so that the light components bypass the convection section. Incertain operations, co-produced LPG, and in certain embodimentsnaphtha-range byproducts components can pass to the convection sectionwith the feed to the steam cracking unit. Integration of a naphthareformer provides H₂ production and additional feed for BTX splitting,so that the overall process dynamics are improved.

FIGS. 1 and 2 are process flow diagrams of embodiments of integratedsteam cracking processes and systems including refractory PFO treatment.The systems generally include a steam cracker/separation zone 10; a PFOtreatment zone 20 including a hydrodealkylation zone 30, a separationzone 36 and a BTX splitting zone 56; a gas treatment zone 74; and areforming zone 80. In certain embodiments, a trans-alkylation zone 66 isalso integrated in the PFO treatment zone 20. In the embodiment of FIG.1 the PFO treatment zone 20 also includes a refractory PFO separationzone 22.

The steam cracking reaction and separation zone is schematically shownat 10. The steam cracking reaction and separation zone includes heaters,furnaces, separation vessels and auxiliary units for steam cracking ofan initial steam cracking feed 12 and recycle streams (including LPG andin certain embodiments one or more naphtha streams) created during oneor more PFO treatment steps disclosed herein, for production of one ormore mixed hydrocarbon product streams, and for separation generallyinto light gases, olefins, pygas and PFO. The steam cracking reactionseparation occurs as is commonly known, for instance, using primaryfractionating, quench separation and olefins recovery to generallyobtain one or more C2, C3 and/or C4 olefins streams 14, a pygas (C5-C9range) stream 16 and a PFO (C9+) stream 18. In operations in which thesteam cracker is operable to treat an initial stream 12 including orconsisting of treated crude oil and/or heavy feedstocks, a refractoryPFO stream 18 is produced that is processed in accordance withembodiments described herein.

In the embodiments of FIG. 1, the steam cracking reaction and separationzone 10 is in fluid communication with the separation zone 22 toseparate the PFO stream 18 into a first stream 26 containing C9+aromatics compounds with one benzene ring and C10+ aromatics compoundswith no less than 2 and up to 6 (typically between 2 and 4) benzenerings, and a second stream 28 containing heavy C20+ polyaromatics suchas those having 6 or more benzene rings (a “poly C20+” stream). Incertain embodiments, a substantial portion, a significant portion or amajor portion of PFO stream 18 produced from the steam cracking zone 10is passed to the separation zone 22. The separation zone 22 can includeone or more flash vessels and/or one or more simple or fractionaldistillation columns. Recovered streams from the separation zone 22include the first stream 26 containing hydrocarbons having a lower limitin the range of about 130-150° C. and an upper limit in the range ofabout 350-430, for instance, about 130-430, 140-430, 150-430, 130-400,140-400, 150-400, 130-375, 140-375, 150-375, 130-350, 140-350 or150-350° C., and the second stream 28 containing hydrocarbons boilingabove about the range of about 350-430, for instance above about 350,375, 400 or 430° C.

The separation zone 22 is in fluid communication with thehydrodealkylation zone 30 to pass all or a portion of the first stream26. In certain embodiments, a substantial portion, a significant portionor a major portion of the first stream 26 is passed from the separationzone 22 to the hydrodealkylation zone 30. In certain embodiments, theseparation zone 22 is in fluid communication with a fuel oil pool or theinitial feed treatment zone upstream of the steam cracker to pass all ora portion of the poly C20+ stream 28 (also referred to as a heavy PFOpoly C20+ stream) for processing outside of the integrated system, forinstance in a fuel oil blending step (not shown), or as a recycle streamto the initial feed treatment zone. In certain embodiments, all, asubstantial portion, a significant portion or a major portion of thepoly C20+ stream 28 is recycled to the initial feed treatment zoneupstream of the steam cracker.

In certain embodiments, with reference to FIG. 2, the separation zone 22shown in FIG. 1 is not used, so that all or a portion of the full rangeof the C9+ PFO stream 18 is sent to the hydrodealkylation zone 30. Incertain embodiments, a substantial portion, a significant portion or amajor portion of the full range of the C9+ PFO stream 18 is routed tothe hydrodealkylation zone 30.

The hydrodealkylation zone 30 is in fluid communication with stream 26,stream 26 and all or a portion of stream 28, or stream 18. Thehydrodealkylation zone 30 contains one or more reactors in series orparallel arrangement operating under conditions effective for, and usingcatalyst effective for, selective hydrogenation and selectivehydrocracking of the polyaromatics compounds contained in stream 26,stream 26 and all or a portion of stream 28, or stream 18. A hydrogenstream 32 is in fluid communication with the reactor(s) at one or morelocations as is known, and can be derived from recycled hydrogen fromthe integrated steam cracking unit (not shown in FIGS. 1 and 2),produced hydrogen 76 from the gas treatment zone 74, and hydrogen 90from the reforming zone 80. A make-up hydrogen stream from anothersource (not shown) can also be in fluid communication with thereactor(s) at one or more locations as is known. Reaction conditions areset in the hydrodealkylation zone 30 to (a) maximize the conversion ofpolyaromatics, such as naphthalene, methylnaphthalene, anthracene,naphtheno-diaromatics (three rings, one saturated and two aromatic), byselective hydrogenation into aromatic compounds with one benzene ring,and (b) selective ring opening functions and hydrodealkylationfunctions, targeting aromatic compounds with one benzene ring, tomaximize the selective ring opening (preserving the aromatic ringstructure) into benzene, toluene, and xylenes (BTX), and/orethylbenzene.

The catalysts used in the hydrodealkylation zone 30 can include multiplebeds of different functional catalysts, multiple reactors of differentfunctional catalysts, a mixture of different functional catalysts in areactor, or multi-functional catalysts in a reactor. In certainembodiments, selective hydrogenation catalysts used in thehydrodealkylation zone 30 can be, for instance, an acid or metalcatalyst, and in certain embodiments dual functionality catalystmaterials or a combination of catalyst materials having differentfunctionalities of cracking and hydrogenation. In certain embodiments,selective hydrocracking catalysts used in the hydrodealkylation zone 30can be selective ring opening and hydrodealkylation catalysts. Incertain embodiments, a combined catalysts material can be used thatincludes functionalities for selective hydrogenation and selectivehydrocracking, for instance, with different active components depositedor otherwise incorporated on a support material.

The effluent product stream 34 containing BTX and other generallyheavier components is sent to the separation zone 36 for separation ofthe light gases, stream 38 including LPG and H₂, from the remaindereffluent product stream 34 containing of the BTX+ components, ahydrodealkylated stream 42. In certain embodiments, the separation zone36 can be a fractionator associated with the hydrodealkylation reactorwhich operates similarly to a fractionator conventionally used inconjunction with a hydroprocessing zone. The LPG/H₂ stream 38 is passedto the gas treatment zone 74. The effluent product stream 34 having alight gas stream 38 removed, the BTX+ stream 42, is routed to the BTXsplitting zone 56 for separation.

Conditions and catalysts are selected in the hydrodealkylation zone 30to minimize production of non-aromatic naphtha range products, and anynaphtha including light naphtha in the effluent product stream 34 can bepassed to the BTX splitting zone 56. In operations in which appreciablenaphtha is formed, it can be passed to the steam cracking zone 10 asadditional feed, or it can be passed to the reforming zone 80 as all ora portion of a reformer naphtha feed stream 82. In further embodiments,any naphtha can be optionally separated separation zone 36, shown indashed lines as stream 40, that is in fluid communication with the steamcracking zone 10 and/or the reforming zone 80.

In certain embodiments, all or some of the gas treatment steps for theLPG/H₂ stream 38 is accomplished by a separate gas treatment zone 74 asshown, or alternatively with other gas treatment operations. In certainembodiments, recovered hydrogen 76 is passed to hydrogen users in theintegrated process and system. In certain embodiments, an LPG stream 78obtained from stream 38 (as shown via the gas treatment zone 74) ispassed to the steam cracker as additional feed (not shown). In otherembodiments, the light gas stream 38 can be routed to gas treatmentoperations associated with the steam cracking and separation zone and/orgas treatment operations within a hydroprocessing unit used fortreatment of the initial feed upstream of the steam cracking zone (notshown).

In certain optional embodiments (shown in dashed lines), the separatedeffluent hydrodealkylated BTX+ stream 42 can be passed to an aromaticsseparation unit 50, whereby an aromatics rich stream 52 (typically anextract stream) is passed to the BTX splitting zone 56, and an aromaticslean stream 54 (typically a raffinate stream) which can include C5 andnon-aromatic C6 components (light wild naphtha) is separately processed.In certain embodiments, all, a substantial portion, a significantportion or a major portion of the aromatics lean stream 54 is recycledto the steam cracking zone 10.

The feed to the BTX splitting zone 56 also includes a reformer BTXstream 84 from the reforming zone 80. A naphtha stream 82 is processedin the reforming zone 80 as is known for production of aromatics (BTXand other C8+ aromatics in a reformer BTX stream 84), a by-products LPGstream 88, and a hydrogen stream 90. In the integrated process andsystem herein, the LPG stream 88 is routed to the gas treatment zone 74and/or directly to the steam cracker/separation zone 10, and thereformer BTX stream 84 containing BTX and other C8+ aromatic compoundsis routed to the BTX splitting zone 56 for separation. Hydrogen 90 canbe routed to the hydrogen users in the integrated process and system.

In certain optional embodiments (shown in dashed lines), the reformingzone 80 is operable to remove at least a portion of non-aromatic contentfrom the reaction products, for instance by including an aromaticsextraction step within the reformer process, and an aromatics leanstream 86 (typically a raffinate stream) which can include non-aromaticnaphtha range components is separately processed. In certainembodiments, all, a substantial portion, a significant portion or amajor portion of the aromatics lean stream 86 is recycled to the steamcracking zone 10.

In other optional embodiments (shown in dashed lines), the reformerproducts stream 84 can be passed to an aromatics separation unit 92,whereby an aromatics rich stream 94 (typically an extract stream) ispassed to the BTX splitting zone 56, and an aromatics lean stream 96(typically a raffinate stream), which can include C5 and non-aromatic C6components (light wild naphtha), is separately processed. In certainembodiments, all, a substantial portion, a significant portion or amajor portion of the aromatics lean stream 96 is recycled to the steamcracking zone 10. Note that while the aromatics separation unit 92 andthe aromatics separation unit 50 are shown as separate units, in certainembodiments these can be combined as a common unit.

The BTX splitting zone 56 separates the hydrodealkylated BTX+ stream 42from the hydrodealkylation zone 30 (via separator 36) into a BTX productstream 58, which can be one or more streams that are typically passed toa BTX complex (not shown) for separation into C6, C7 and C8 streams,benzene, toluene and one more xylene products (BTX), and in certainembodiments benzene, toluene, one more xylene products and ethylbenzene(BTXE). The BTX splitting zone 56 can include one or more simple orfractional distillation columns. In addition, the reforming zone 80 isintegrated so that the reformate stream rich in BTX, stream 84, is alsorouted to the BTX splitting zone 56 for separation.

In certain optional embodiments (shown in dashed lines), the BTXsplitting zone 56 is operable to remove at least a portion ofnon-aromatic content from the hydrodealkylated BTX+ stream 42, forinstance by including an aromatics extraction step, and an aromaticslean stream 60 (typically a raffinate stream) which can includenon-aromatic components, including C5 and non-aromatic C6 components(light wild naphtha), is recovered and separately processed. In certainembodiments, all, a substantial portion, a significant portion or amajor portion of the aromatics lean stream 60 is recycled to the steamcracking zone 10.

In other optional embodiments the aromatics separation unit 50 isincluded upstream of the BTX splitting zone 56 for removing thearomatics lean stream 54 containing non-aromatic components from thefeeds to the BTX splitting zone 56, including C5 and non-aromatic C6components (light wild naphtha), and the aromatics rich stream 52 ispassed to the BTX splitting zone 56.

In certain embodiments, a C9 stream 62 is recovered, which includestrimethyl-benzene, methylethylbenzene, and other C9 compounds. Inadditional embodiments, the C9 stream 62 is passed to a transalkylationzone 66 to further produce BTX via transalkylation reactions, shown as aBTX stream 70.

A heavy product stream 64 from the BTX splitting zone 56 (a C10+fraction) can be purged as stream 64(p) and used, for instance, as fueloil, recycled back to the hydrodealkylation zone 30 for furtherconversion as stream 64(r), recycled to the initial feed treatment zoneupstream of the steam cracker (not shown), recycled to the steam cracker(not shown), or a combination of these. In certain embodiments, all, asubstantial portion, a significant portion or a major portion of theheavy product stream 64 recycled as stream 64(r) to thehydrodealkylation zone 30 for further conversion into BTX and C9s. Incertain embodiments, all, a substantial portion, a significant portionor a major portion of the heavy product stream 64 recycled to theinitial feed treatment zone upstream of the steam cracker. In certainembodiments, all, a substantial portion, a significant portion or amajor portion of the heavy product stream 64 recycled to the steamcracker.

In embodiments in which a transalkylation step is integrated, thetransalkylation zone 66 operates in the presence of hydrogen, stream 68,to catalytically convert the C9+ aromatic stream 62 into additional BTXcomponents, stream 70, through transalkylation and disproportionationreactions. In certain embodiments (not shown) all or a portion ofbenzene and/or toluene recovered from stream 58, or benzene and/ortoluene from another source, is also introduced to the transalkylationzone 66 for production of additional xylenes. In the integrated processand system herein, the light gases by-product stream 72 from thetransalkylation zone 66, including C₁-C₄ and hydrogen, is routed to thegas treatment zone 74 (or alternatively to the steam cracker/separationzone 10, not shown), and the effluent stream 70 containing BTX is passedback to the BTX splitting zone 56. In certain optional embodiments, theeffluent stream 70 is passed to an aromatics extraction step within theBTX splitting zone 56 and non-aromatic components are included with anaromatics lean stream 60. In certain optional embodiments, the effluentstream 70 can be passed to an aromatics separation unit, for instanceunit 50 or a separate extraction unit, whereby an aromatics rich stream(typically an extract stream) is passed back to the BTX splitting zone56, and an aromatics lean stream (typically a raffinate stream), whichcan include C5 and non-aromatic C6 components (light wild naphtha), isrecovered and separately processed. In certain embodiments, all, asubstantial portion, a significant portion or a major portion of thearomatics lean stream derived from the transalkylation effluent stream70 is recycled to the steam cracking zone 10.

The gas treatment zone 74 collects light gas streams from the integratedprocess and system including from the reforming zone (stream 88), fromthe transalkylation zone (stream 72), and/or from the hydrodealkylationzone (stream 38). The gas treatment zone 74 can be a suitable knownsystem including hydrogen purification units, such as a pressure swingadsorption (PSA) unit to obtain a hydrogen stream 76 having a purity of99.9%+, or a membrane separation unit to obtain a hydrogen stream 76with a purity of about 95%. In certain embodiments, the gas treatmentzone 74 is also configured and arranged for recovery of naphtha rangeproducts, such as light naphtha. LPG and heavier components, stream 78,is passed to the steam cracking zone 10. Recovered hydrogen, stream 76,is sent to one or more of the hydrogen users in the integrated processand system.

Steam pyrolysis is a relatively complex process employing very hightemperatures, high flow rates and production of large amounts offlammable gases. Steam cracker arrangements are well known and typicallyinclude several furnaces which are divided in a radiation (or pyrolysis)section, and a convection section. In a typical configuration,vaporization of the feed occurs in the convection section, recoveringthe flue gases heat from the radiation section. Vaporization isfacilitated by mixing the hydrocarbons and steam. Steam is also producedin the convection section. Typically steam to oil ratio values rangefrom about 0.3:1.0 to about 1.0:1.0, with the lower end suitable forlighter feeds such as ethane and the higher end suitable for heavierfeeds. In steam cracking of heavier feeds including treated crude oil,the steam to oil ratio can be as high as 1:0:1:0 to 5:0:1:0. Steamcracker furnaces maximize recovery of flue gas energy via production ofhigh pressure steam, which can be recovered for use elsewhere in therefinery and/or petrochemical operations.

The thermal cracking reactions occur mainly in the radiation section,typically at a set of coils. The number and shape of coils depend of thetype of feed, and varies, for instance, depending on the selectedconfiguration. Hydrocarbon steam cracking is an endothermic reactionthat commences at coil inlet temperature (CIT), for instance, in therange of about 600-650° C., and finishes at a coil outlet temperature(COT), for instance, in the range of about 800-850° C. The values of theCIT and COT vary, for instance, +/−25%, based on factors such as theseverity of the operation, the type of feed and the selectedconfiguration. The furnaces are followed in the process by a temperaturequench down targeting to halt thermal cracking reactions and to avoidrecombination of olefins. Following quenching the coil effluent isrouted to a separation section to produce hydrogen, which is can berecovered for use elsewhere in the refinery and/or petrochemicaloperations or used as fuel gas in the steam cracker furnaces, methanewhich is used as fuel gas in the steam cracker furnaces, ethylene asdesired olefin product, propylene as desired olefin product, a mix of C4olefins (butadiene, isobutene, butenes) and normal and iso butanes, apyrolysis gasoline stream rich in aromatics and a PFO stream. Purifiedhydrogen gas can also be recovered with an integrated hydrogenpurification system, for instance using a pressure swing adsorption(PSA) unit to obtain a hydrogen stream having a purity of 99.9%+, or amembrane separation unit to obtain a hydrogen stream with a purity ofabout 95%. In certain embodiments, the gas treatment zone 74 describedabove associated with the PFO treatment steps could be integrated withgas treatment operations for steam cracker products.

Units that are included in separation section include a primaryfractionator after quench, water tower(s), gas compressor(s), a cold boxand a series of distillations columns such as a demethanizer,deethanizer, ethylene-ethane splitter, depropanizer andpropane-propylene splitter. The ethane and propane produced aretypically recycled to the furnaces to extinction.

While a generalized description is provided above for steam cracking, itshould be appreciated that other arrangements and conditions used forthermal cracking that produce the refractory PFO streams describedherein can benefit from integration of the PFO treatments steps herein.In certain embodiments the feed to the steam cracker can be part of anintegrated process and system as disclosed in commonly owned U.S. Pat.No. 9,255,230 (and its related U.S. Pat. Nos. 9,587,185 and 10,017,704),U.S. Pat. No. 9,284,497 (and its related U.S. Pat. No. 10,221,365), U.S.Pat. No. 9,279,088 (and its related U.S. Pat. No. 10,329,499), U.S. Pat.No. 9,296,961 (and its related U.S. Pat. No. 10,344,227), U.S. Pat. No.9,284,502 (and its related U.S. Pat. No. 10,246,651), U.S. Pat. No.9,382,486 (and its related U.S. Pat. No. 10,233,400), U.S. Pat. Nos.9,228,139, 9,228,140, 9,228,141 and 9,284,501 (and its related U.S. Pat.Nos. 9,771,530 and 10,011,788), which are all incorporated by referenceherein in their entireties.

In certain embodiments, a crude oil stream is fed to a hydrotreatingzone, such as a fixed bed or slurry bed reactor in the presence ofhydrogen, where the crude oil is hydrotreated to remove S, N, and otherimpurities. The gas and liquid product are separated, and a stripper isused to remove H₂S and NH₃ from other gas products. In certainembodiments of the processes disclosed in the above-mentioned commonlyowned patents, treated crude oil is used as the feedstock to a steamcracker feedstock. In certain embodiments of the processes disclosed inthe above-mentioned commonly owned patents, a heavy fraction of treatedcrude oil is used as steam cracker feedstock. In certain embodiments, afeedstock hydroprocessing zone carries out selective hydroprocessing orhydrotreating of the initial feed that can increase the paraffin content(or decrease the BMCI) of a feedstock by saturation followed by mildhydrocracking of aromatics, especially polyaromatics. In certainembodiments, when hydrotreating a crude oil or other heavy oil feed,contaminants such as metals, sulfur and nitrogen can be removed bypassing the feedstock through a series of layered catalysts that performthe catalytic functions of demetallization, desulfurization and/ordenitrogenation, for example as disclosed in commonly owned U.S. Pat.No. 9,255,230 (and its related U.S. Pat. Nos. 9,587,185 and 10,017,704).In certain embodiments, hydrotreating a crude oil or other heavy oilfeed to remove contaminants such as metals, sulfur and nitrogen isaccomplished by slurry hydroprocessing as disclosed in commonly ownedU.S. Pat. No. 9,284,501 (and its related U.S. Pat. Nos. 9,771,530 and10,011,788). In certain embodiments, hydrotreating a crude oil or otherheavy oil feed to remove contaminants such as metals, sulfur andnitrogen is preceded by solvent deasphalting, as disclosed in commonlyowned U.S. Pat. No. 9,284,502 (and its related U.S. Pat. No.10,246,651). In certain embodiments, the hydroprocessed effluent fromhydrotreating a crude oil or other heavy oil feed to remove contaminantssuch as metals, sulfur and nitrogen is subjected to solventdeasphalting, as disclosed in commonly owned U.S. Pat. No. 9,382,486(and its related U.S. Pat. No. 10,233,400).

For instance, in one embodiment, a crude oil or other heavy oil,feedstock and an effective amount of hydrogen, are charged to ahydroprocessing reaction zone operating generally at a temperature inthe range of from 300-450° C. In certain embodiments, thehydroprocessing reaction zone includes one or more unit operations. Incertain embodiments, the feed is crude oil and the operations are asdescribed in commonly owned US Patent Publication 2011/0083996 and inPCT Patent Application Publications WO2010/009077, WO2010/009082,WO2010/009089 and WO2009/073436, all of which are incorporated byreference herein in their entireties. The crude oil feedstockhydroprocessing zone can include one or more beds containing aneffective amount of hydrodemetallization catalyst, and one or more bedscontaining an effective amount of hydroprocessing catalyst havinghydrodearomatization, hydrodenitrogenation, hydrodesulfurization and/orhydrocracking functions. In additional embodiments the feedstockhydroprocessing zone includes more than two catalyst beds. In furtherembodiments a feedstock hydroprocessing zone includes plural reactionvessels each containing one or more catalyst beds, for example, ofdifferent function. The reaction vessels(s) in the feedstockhydroprocessing zone operates under parameters effective tohydrodemetallize, hydrodearomatize, hydrodenitrogenate, hydrodesulfurizeand/or hydrocrack the crude oil feedstock. In certain embodiments,hydroprocessing is carried out using the following conditions: operatingtemperature in the range of from about 300-450° C.; operating pressurein the range of from about 30-180 kg/cm²; and a liquid hour spacevelocity in the range of from 0.1-10 h⁻¹. In embodiments using crude oilas the initial feed to the feedstock hydroprocessing zone, certainadvantages are realized as compared to the same hydroprocessing unitoperation employed for atmospheric residue. For instance, at a start ofrun temperature in the range of 370−375° C., the deactivation rate isaround 1° C. per month. In contrast, if residue were to be processed,the deactivation rate would be closer to about 3 to 4° C. per month. Thetreatment of atmospheric residue typically employs pressure of around200 kg/cm′ whereas the present process in which crude oil is treated canoperate at pressures as low as 100 kg/cm′. Additionally, to achieve thehigh level of saturation required for the increase in the hydrogencontent of the feed, this process can be operated at a high throughputwhen compared to atmospheric residue. The LHSV can be as high as 0.5hr⁻¹ while that for atmospheric residue is typically 0.25 hr⁻¹. Thedeactivation rate when hydroprocessing crude oil is going in the inversedirection from that which is usually observed. Deactivation at lowthroughput (0.25 hr⁻′) is 4.2° C. per month and deactivation at higherthroughput (0.5 hr⁻¹) is 2.0° C. per month; this can be attributed tothe washing effect of the catalyst.

Reactor effluents from the feedstock hydroprocessing zone are typicallycooled in an exchanger and sent to a high pressure cold or hotseparator. Separator tops are cleaned in an amine unit and the resultinghydrogen rich gas stream is passed to a recycling compressor and can beused as a recycle gas in the feedstock hydroprocessing reaction zone.Separator bottoms from the high pressure separator, which are in asubstantially liquid phase, are cooled and then introduced to a lowpressure cold separator. Remaining gases, including hydrogen, H₂S, NH₃and any light hydrocarbons, which can include C₁-C₄ hydrocarbons, can beconventionally purged from the low pressure cold separator and sent forfurther processing, such as flare processing or fuel gas processing. Incertain embodiments of the present process, hydrogen is recovered bycombining low pressure separator with gases in the steam crackerproducts. The hydroprocessed effluent contains a reduced content ofcontaminants (such as metals, sulfur and nitrogen), an increasedparaffinicity, reduced BMCI, and an increased American PetroleumInstitute (API) gravity.

In one embodiment, the sequence of catalysts to performhydrodemetallization (HDM) and hydrodesulfurization (HDS) is as follows:(i) A hydrodemetallization catalyst. The catalyst in the HDM section aregenerally based on a gamma alumina support, with a surface area of about140-240 m²/g. This catalyst is best described as having a very high porevolume, for example, in excess of 1 cm³/g. The pore size itself istypically predominantly macroporous. This is required to provide a largecapacity for the uptake of metals on the catalysts surface andoptionally dopants. Typically, the active metals on the catalyst surfaceare sulfides of nickel and molybdenum in the ratio Ni/Ni+Mo<0.15. Theconcentration of nickel is lower on the HDM catalyst than othercatalysts as some nickel and vanadium is anticipated to be depositedfrom the feedstock itself during the removal, acting as catalyst. Thedopant used can be one or more of phosphorus (see, for example, USPatent Publication US 2005/0211603 which is incorporated by referenceherein), boron, silicon and halogens. The catalyst can be in the form ofalumina extrudates or alumina beads. In certain embodiments aluminabeads are used to facilitate un-loading of the catalyst HDM beds in thereactor as the metals uptake will range between from 30 to 100% at thetop of the bed. (ii) An intermediate catalyst can also be used toperform a transition between the HDM and HDS function. It hasintermediate metals loadings and pore size distribution. The catalyst inthe HDM/HDS reactor is essentially alumina based support in the form ofextrudates, optionally at least one catalytic metal from the PeriodicTable of the Elements IUPAC Group 6 (for example, molybdenum and/ortungsten), and/or at least one catalytic metal from the Periodic Tableof the Elements IUPAC Groups 9 or 10 (for example, nickel and/orcobalt). The catalyst also contains optionally at least one dopantselected from boron, phosphorous, halogens and silicon. Physicalproperties include a surface area of about 140-200 m²/g, a pore volumeof at least 0.6 cm³/g and pores which are mesoporous and in the range of12 to 50 nm. (iii) The catalyst in the HDS section can include thosehaving gamma alumina based support materials, with typical surface areatowards the higher end of the HDM range, for example about ranging from180-240 m²/g. This required higher surface for HDS results in relativelysmaller pore volume, for example, lower than 1 cm³/g. The catalystcontains at least one element from the Periodic Table of the ElementsIUPAC Group 6, such as molybdenum and at least one element from thePeriodic Table of the Elements IUPAC Groups 9 or 10, such as nickel. Thecatalyst also comprises at least one dopant selected from boron,phosphorous, silicon and halogens. In certain embodiments cobalt is usedto provide relatively higher levels of desulfurization. The metalsloading for the active phase is higher as the required activity ishigher, such that the molar ratio of Ni/Ni+Mo is in the range of from0.1 to 0.3 and the (Co+Ni)/Mo molar ratio is in the range of from 0.25to 0.85. (iv) A final catalyst (which could optionally replace thesecond and third catalyst) is designed to perform hydrogenation of thefeedstock (rather than a primary function of hydrodesulfurization), forinstance as described in Appl. Catal. A General, 204 (2000) 251. Thecatalyst will be also promoted by Ni and the support will be wide poregamma alumina. Physical properties include a surface area towards thehigher end of the HDM range, for example, 180-240 m²/g This requiredhigher surface for HDS results in relatively smaller pore volume, forexample, lower than 1 cm³/g.

In certain embodiments the bottoms stream from the low pressure coldseparator is the feed to the steam pyrolysis zone. In additionalembodiments, bottoms from the low pressure separator are sent to aseparation zone wherein heavy materials such as those in the atmosphericor vacuum residue range are removed from the system, and the remainderis passed to the steam pyrolysis zone. In further embodiments, bottomsfrom the low pressure separator are sent to a separation zone wherein alight portion bypasses all or a portion of the steam pyrolysis zone, anda heavy portion serves as feed to a convection section of a steampyrolysis zone. The separation zone can include a suitable separationunit operation such as a flash vessel or distillation column thatseparates based on boiling point, a separation device based on physicalor mechanical separation of vapors and liquids, or a combinationincluding at least one of these types of devices.

FIGS. 3-6 schematically depict embodiments of steam cracking systemsintegrating pretreatment of the feed. The steam cracking zone 10operates as described above and is schematically shown as including asteam cracking convection section 102 and a steam cracking pyrolysissection 112. The steam cracking feed 12 (which can be a hydroprocessedinitial feed 126 as in FIG. 3; a hydroprocessed initial feed having abottom fraction removed, stream 136 as in FIG. 4; a hydroprocessedinitial feed having tops removed, stream 144 as in FIG. 5; or adeasphalted stream 156 as in FIG. 6) is passed to the steam crackingconvection section 102 along with steam for vaporization of the feed. Aheated stream 104 is passed to the steam cracking pyrolysis section 112for thermal cracking reactions and to produce a thermally cracked mixedproduct stream 114. In certain embodiments, a separation zone 106 isincluded between the steam cracking convection section 102 and the steamcracking pyrolysis section 112. A light portion, stream 108 from theseparation zone 106, is passed to the steam cracking pyrolysis section112, and a heavy portion 110 is discharged. The thermally cracked mixedproduct stream 114 is passed to a steam cracking effluent separationzone 116 which can operate as is commonly known, for instance, usingprimary fractionating, quench separation and olefins recovery togenerally obtain one or more C2, C3 and/or C4 olefins streams 14, apygas (C5-C9 range) stream 16 and a PFO (C9+) stream 18. In certainembodiments, the steam cracking effluent separation zone 116 alsoincludes or is integrated with a suitable hydrogen purification units,such as a pressure swing adsorption (PSA) unit to obtain a hydrogenstream 118 having a purity of 99.9%+, or a membrane separation unit toobtain a hydrogen stream 118 with a purity of about 95%. Methane (notshown) can also be recovered and used as fuel gas in the steam crackerfurnaces or other fuel gas users within the integrated system. The PFOstream 18 is passed to a PFO treatment zone 20.

In one embodiment, with reference to FIG. 3, a schematic process flowdiagram of a feedstock hydroprocessing zone and a steam cracking zone isshown, including a feedstock hydroprocessing zone 122 for treating aninitial feedstock 120 (and optionally a recycle stream 64(r) asdescribed herein) in the presence of hydrogen, shown as hydrogen stream124, to produce a hydroprocessed effluent stream 126 that serves as thesteam cracking feed 12. As noted herein, the effluent can be subjectedto a high pressure cold or hot separator to obtain a hydrogen rich gasstream that is used as a recycle gas in the reactor of the feedstockhydroprocessing zone 122. A separator bottoms stream from the highpressure separator, in a substantially liquid phase, is cooled and thenintroduced to a low pressure cold separator. A separator bottoms streamfrom the low pressure separator, in a substantially liquid phase, is thestream 126 that serves as the steam cracking feed 12.

In another embodiment, with reference to FIG. 4, a schematic processflow diagram of a feedstock hydroprocessing zone and a steam crackingzone is shown, including a feedstock hydroprocessing zone 122 fortreating an initial feedstock 120 (and optionally a recycle stream 64(r)as described herein) in the presence of hydrogen, shown as hydrogenstream 124, to produce a hydroprocessed effluent stream 126. Thehydroprocessed effluent is passed to a separation zone 132 upstream ofthe steam cracking zone to remove heavy components such as residualrange components as a stream 134, and the remainder of the bottomlessfeed, in certain embodiments bottomless crude oil, stream 136, serves asthe steam cracking feed 12. The hydroprocessed effluent can be subjectedto a high pressure cold or hot separator to obtain a hydrogen rich gasstream that is used as a recycle gas in the reactor of the feedstockhydroprocessing zone 122. A separator bottoms stream from the highpressure separator, in a substantially liquid phase, is cooled and thenintroduced to a low pressure cold separator. A separator bottoms streamfrom the low pressure separator, in a substantially liquid phase, is thestream 126 that is passed to the separation zone 132 to remove residualrange components as a heavy stream 134; the remaining stream 136 servesas the steam cracking feed 12. In certain embodiments the heavy stream134 has an initial boiling point corresponding to vacuum residue, forinstance in the range of about 500-550, 500-540, 500-530, 510-550,510-540 or 510-530° C. The bottomless stream 136 can have, for instance,an initial boiling point corresponding to that of the stream 126 and anend boiling point corresponding to the initial boiling point of theheavy stream 134.

In another embodiment, with reference to FIG. 5, a schematic processflow diagram of a feedstock hydroprocessing zone and a steam crackingzone is shown, including a feedstock hydroprocessing zone 122 fortreating an initial feedstock 120 (and optionally a recycle stream 64(r)as described herein) in the presence of hydrogen, shown as hydrogenstream 124, to produce a hydroprocessed effluent stream 126. Thehydroprocessed effluent is passed to a separation zone 142 upstream ofthe steam cracking zone to remove light components, stream 146, and theremaining heavy components, in certain embodiments a toppedhydroprocessed initial feed, stream 144, serves as the steam crackingfeed 12. The hydroprocessed effluent can be subjected to a high pressurecold or hot separator to obtain a hydrogen rich gas stream that is usedas a recycle gas in the reactor of the feedstock hydroprocessing zone122. A separator bottoms stream from the high pressure separator, in asubstantially liquid phase, is cooled and then introduced to a lowpressure cold separator. A separator bottoms stream from the lowpressure separator, in a substantially liquid phase, is the stream 126that is passed to the separation zone 142 to separate remove lightcomponents, stream 146; the remainder, stream 144, serves as the steamcracking feed 12. In certain embodiments the stream 146 has an endboiling point corresponding to that of naphtha or light naphtha, and thestream 144 has an initial boiling point corresponding to the end boilingpoint of the stream 146.

In the embodiments of FIGS. 3, 4 and 5, the initial feedstock 120 can beas described herein, for instance selected from crude oil and otherheavy oil streams such as those in the atmospheric gas oil range,atmospheric residue range, vacuum gas oil range and/or vacuum residuerange.

In another embodiment, with reference to FIG. 6, a schematic processflow diagram of a feedstock deasphalting zone and a steam cracking zoneis shown, including a feedstock deasphalting zone 152 for treating adeasphalting feedstock 154 (and optionally a recycle stream 64(r) asdescribed herein) to produce a deasphalted oil stream 156 and an asphaltphase stream 158. In certain embodiments, the deasphalting feedstock 154can be an initial feed as described herein, for instance selected from atreated crude oil stream and other treated heavy oil streams such asthose in the atmospheric gas oil range, atmospheric residue range,vacuum gas oil range and/or vacuum residue range. In certainembodiments, the deasphalting feedstock 154 can be all or a portion of ahydroprocessed effluent, for instance, a hydroprocessed initial feed 126as described with respect to FIG. 3; a hydroprocessed initial feedhaving a bottom fraction removed, stream 136 as described with respectto FIG. 4; or a hydroprocessed initial feed having tops removed, stream144 as described with respect to FIG. 5. In further embodiments, thedeasphalting feedstock 154 can be an initial feed as described herein,and the deasphalted oil stream 156 is passed to an optionalhydroprocessing zone, schematically shown as zone 162. For instance, thedeasphalted oil stream 156 can serve as the initial feed 120 in theintegrated systems described with respect to FIGS. 3, 4 and 5. Incertain embodiments, the optional zone 162 can be a separation zone, forinstance that operates similar to the pre-steam cracking separation zone132 described with respect to FIG. 4 to pass a bottomless stream 136 asthe steam cracking feed 12, or similar to the pre-steam crackingseparation zone 142 described with respect to FIG. 5 to pass a toppedfeed 144 as the steam cracking feed 12.

In embodiments in which solvent deasphalting is employed prior to thesteam cracking zone (either before hydroprocessing of the initial feed,between hydroprocessing of the initial feed and steam cracking, or inthe absence of hydroprocessing of the initial feed), solventdeasphalting can be carried out with paraffin streams having carbonnumber ranging from 3-7, in certain embodiments ranging from 4-5, atconditions that are below the critical temperature and pressureconditions of the solvent. The feed is mixed with the light paraffinicsolvent, where the deasphalted oil is solubilized in the solvent. Theinsoluble pitch will precipitate out of the mixed solution and isseparated from the DAO phase (solvent-DAO mixture) in the extractor.Solvent deasphalting is carried-out in liquid phase and therefore thetemperature and pressure are set accordingly. There are typically twostages for phase separation in solvent deasphalting. In the firstseparation stage, the temperature is maintained lower than that of thesecond stage to separate the bulk of the asphaltenes. The second stagetemperature is maintained to control the deasphalted/demetalized oil(DA/DMO) quality and quantity. The temperature impacts the quality andquantity of DA/DMO. An increase in the extraction temperature willresult in a decrease in deasphalted/demetalized oil yield, which meansthat the DA/DMO will be lighter, less viscous, and contain less metals,asphaltenes, sulfur, and nitrogen. A temperature decrease will have theopposite effects. In general, the DA/DMO yield decreases having higherquality, by raising extraction system temperature; and increases, havinglower quality, by lowering extraction system temperature. Thecomposition of the solvent is an important process variable. Thesolubility of the solvent increases with increasing criticaltemperature, generally according to C3<iC4<nC4<iC5. An increase incritical temperature of the solvent increases the DA/DMO yield. However,it should be noted that the solvent having the lower criticaltemperature has less selectivity resulting in lower DA/DMO quality. Thevolumetric ratio of the solvent to the solvent deasphalting unit chargeimpacts selectivity and to a lesser degree on the DA/DMO yield. Highersolvent-to-oil ratios result in a higher quality of the DA/DMO for afixed DA/DMO yield. Higher solvent-to-oil ratio is desirable due tobetter selectivity. The composition of the solvent will also help toestablish the required solvent to oil ratios. The required solvent tooil ratio decreases as the critical solvent temperature increases. Thesolvent to oil ratio is, therefore, a function of desired selectivity,operation costs and solvent composition.

The hydrodealkylation zone 30 includes an effective reactorconfiguration with the requisite reaction vessel(s), feed heaters, heatexchangers, hot and/or cold separators, product fractionators,strippers, and/or other units to process all or a portion of the stream26 from the PFO separation zone 22 containing C9+ aromatics compoundswith one benzene ring and C10+ aromatics compounds with no less than 2and up to 6 (typically between 2 and 4) benzene rings, or all or aportion of the PFO C9+ stream 18 from the steam cracker/separation zone10. The hydrodealkylation zone 30 generally contains one or more fixedbed, fluidized bed, ebullated bed, slurry bed, moving bed, continuousstirred tank, or tubular reactors, in series or parallel arrangement,which is/are generally operated in the presence of hydrogen underconditions, and utilizes catalyst(s), effective for conversion ofpolyaromatics, such as naphthalene, methylnaphthalene, anthracene,C4-benzene, C5-benzene, naphtheno-diaromatics, by partial hydrogenation(preserving one aromatic ring) and selective ring opening (preservingthe aromatic ring structure), into benzene and alkylbenzenes, forinstance benzene, toluene and xylenes (BTX). For example, a polyaromaticsuch as naphthalene or methylnaphthalene is converted to an ortho-fusedbicyclic hydrocarbon having one aromatic ring preserved, such astetralin and derivatives. The non-aromatic ring is cracked to yield BTXcompounds, other alkylbenzenes, LPG and naphtha. In certain embodiments,multiple reactors can be provided in parallel in hydrodealkylation zone30 to facilitate catalyst replacement and/or regeneration. Thehydrodealkylation zone 30 generally includes a reaction vessel havingmultiple beds of different functional catalysts, multiple reactionvessels of different functional catalysts, a mixture of differentfunctional catalysts in a reaction vessel, multi-functional catalysts ina reaction vessel, or a mixture of different functional catalysts andmulti-functional catalysts in a reaction vessel. In embodimentsincluding a reaction vessel having multiple beds of different functionalcatalysts, or multiple reaction vessels of different functionalcatalysts, polyaromatics are selectively hydrogenated, and resultingsingle ring compounds are selectively hydrocracked/dealkylated. Inembodiments including a mixture of different functional catalysts,and/or or multi-functional catalysts, in a reaction vessel, thepolyaromatics are subjected to selective hydrogenation and selectivehydrocracking.

The hydrodealkylation zone 30 generally has one or more inlets in fluidcommunication with a source of feedstock. In certain embodiments, thefeedstock is all or a portion of the stream 26 containing C9+ aromaticscompounds with one benzene ring and C10+ aromatics compounds with noless than 2 and up to 6 (typically between 2 and 4) benzene rings (asdisclosed in conjunction with the embodiment of FIG. 1). In certainembodiments, the feedstock is all or a portion of the full range PFO C9+stream from the steam cracker/separation zone 10 (as disclosed inconjunction with the embodiments of FIG. 2). The hydrodealkylation zone30 is in fluid communication with a hydrogen stream 32. The hydrogenstream 32 can be passed to the reactors at one or more locations as isknown, and can be derived from sources including recycled hydrogen fromthe integrated steam cracking unit (not shown in FIGS. 1 and 2),produced hydrogen 76 from the gas treatment zone 74, and hydrogen 90from the reforming zone 80. Make-up hydrogen from another source (notshown) is also typically added.

The outlet(s) of the hydrodealkylation zone 30 discharge the effluentstream 34, and in fluid communication with one or more inlets of theseparation zone 36. The separation zone 36 can include one or moresimple or fractional distillation columns and generally includes one ormore outlets for discharging light gases, stream 38 including LPG andH₂, and the remainder of the effluent stream 34, the hydrodealkylatedstream 42. One or more outlets that discharge the effluent stream 42 arefluid communication with one or more inlets of the BTX splitting zone56. In certain embodiments (not shown), effluents from the reactionvessels are cooled in an exchanger and sent to a high pressure cold orhot separator and liquid effluents are passed to the BTX splitting zone56. In certain embodiments, the one or more outlets of reaction zonethat discharge the hydrodealkylated effluent stream 42 are in fluidcommunication with one or more inlets of the aromatics extraction zone50, whereby the extract 52 is passed to the BTX splitting zone 56.

In operation, the hydrodealkylation feedstock and a hydrogen stream arecharged to the reactor of the hydrodealkylation zone 30. The hydrogenstream contains an effective quantity of hydrogen to support theselective hydrogenation and hydrocracking of the polyaromatics compoundsin the feed, the reaction conditions, the selected catalysts and otherfactors, and can be any combination including recycle hydrogen fromoptional gas separation subsystems (not shown) between the reaction zoneand fractionating zone, hydrogen derived from the hydrogen producerswithin the integrated system and process, stream 76, and in certainembodiments 90, and make-up hydrogen as necessary.

The hydrodealkylation reaction effluent stream is typically passed toone or more high pressure and low pressure separation stages recoverrecycle hydrogen. For example, effluents from the hydrodealkylationreaction vessel are cooled in an exchanger and sent to a high pressurecold or hot separator. Separator tops are cleaned in an amine unit andthe resulting hydrogen rich gas stream is passed to a recyclingcompressor to be used as a recycle gas in the hydrodealkylation reactionvessel. Separator bottoms from the high pressure separator, which are ina substantially liquid phase, are cooled and then introduced to a lowpressure cold separator. Remaining gases including hydrogen and anylight hydrocarbons, which can include C₁-C₄ hydrocarbons, can beconventionally purged from the low pressure cold separator and sent forfurther processing, for instance to the gas treatment zone 74. Theliquid stream from the low pressure cold separator is passed to theseparation zone 36, generally to recover an LPG/H₂ stream 38 and thehydrodealkylated BTX+ stream 42. In certain embodiments, thefractionating zone can operate as one or more flash vessels to separateheavy components at a suitable cut point, for example, a rangecorresponding to the hydrodealkylated BTX+ stream 42 that is passed tothe BTX splitting zone 56.

Reaction operating conditions and catalysts are selected so as tomaximize the conversion of polyaromatics, such as naphthalene,methylnaphthalene, anthracene, naphtheno-diaromatics (three rings, onesaturated and two aromatic), into BTX components by hydrodealkylation,including selective hydrogenation into aromatic compounds with onebenzene ring and selective ring opening and hydrodealkylation. Forexample, the hydrodealkylation zone 30 can generally operates undereffective conditions including:

-   -   a reaction temperature (° C.) in the range of about 300-550,        300-500, 300-450, 320-550, 320-500, 320-450, 350-550, 350-500,        or 350-450° C.;    -   a reaction pressure (hydrogen partial pressure, kg/cm²) in the        range of about 3-30, 3-25, 3-20, 5-30, 5-25, 5-20, 10-30, 10-25,        10-20 kg/cm²;    -   a hydrogen feed rate (standard liters per liter of hydrocarbon        feed, SLt/Lt) in the range of about 1-30, 1-25, 1-20, 5-30,        5-25, 5-20 SLt/Lt; and    -   a LHSV in the range of about 0.1-10, 0.1-8, 0.1-5, 0.5-10,        0.5-8, 0.5-5, 1-10, 1-8, or 1-5.

In certain embodiments, in which C20+ are substantially removed prior tothe hydrodealkylation zone 30, effective operating conditions include:

-   -   a reaction temperature (° C.) in the range of about 300-500,        300-450, 320-500, or 320-450° C.;    -   a reaction pressure (hydrogen partial pressure, kg/cm²) in the        range of about 3-25, 3-20, 5-25, 5-20, 10-25, 10-20 kg/cm²;    -   a hydrogen feed rate (standard liters per liter of hydrocarbon        feed, SLt/Lt) in the range of about 1-25, 1-20, 5-25, 5-20        SLt/Lt; and    -   a LHSV in the range of about 0.1-8, 0.1-5, 0.5-8, 0.5-5, 1-8, or        1-5.

In certain embodiments, in which the C9+ PFO stream is used as feed(without separation of C20+) to the hydrodealkylation zone 30, effectiveoperating conditions include:

-   -   a reaction temperature (° C.) in the range of about 300-550,        300-500, 300-450, 350-550, 350-500, or 350-450° C.;    -   a reaction pressure (hydrogen partial pressure, kg/cm²) in the        range of about 3-30, 3-25, 3-20, 5-30, 5-25, 5-20, 10-30, 10-25,        10-20 kg/cm²;    -   a hydrogen feed rate (standard liters per liter of hydrocarbon        feed, SLt/Lt) in the range of about 1-30, 1-20, 5-30, 5-20        SLt/Lt; and    -   a LHSV in the range of about 0.1-10, 0.1-8, 0.1-5, 0.5-10,        0.5-8, 0.5-5, 1-10, 1-8, or 1-5.

Suitable catalyst effective for conversion of polyaromatics to BTXcomponents in the hydrodealkylation zone 30 include multiple beds ofdifferent functional catalysts in a reaction vessel, multiple reactionvessels in series having different functional catalysts, a mixture ofdifferent functional catalysts in a reaction vessel, or multi-functionalcatalysts in a reaction vessel. In embodiments in which differentfunctional catalysts are used, a first functional catalyst includesselective hydrogenation catalysts such as an acid or metal catalyst, andin certain embodiments dual functionality catalyst materials or acombination of catalyst materials having different functionalities ofcracking and hydrogenation; and a second functional catalyst includesselective hydrocracking catalysts such as selective ring opening andhydrodealkylation catalysts. In embodiments in which multi-functionalcatalysts are used, a combined catalysts material can be used thatincludes functionalities for selective hydrogenation and selectivehydrocracking, for instance, with different active components depositedor otherwise incorporated on a support material.

The first functional catalyst used in the hydrodealkylation zone 30 canbe one or more conventionally known, commercially available or futuredeveloped hydrogenation catalysts effective to maximize the conversionof polyaromatics, such as naphthalene, methylnaphthalene, anthracene,naphtheno-diaromatics (three rings, one saturated and two aromatic), byselective hydrogenation into aromatic compounds with one benzene ring.The selection, activity and form of the selective hydrogenation catalystcan be determined based on factors including but not limited tooperating conditions, selected reactor configuration, feedstockcomposition, and desired degree of conversion. Dual functionality,hydrogenating and cracking, catalysts are useful for conversion ofselective conversion of polycyclic aromatic compounds into aromaticcompounds or bicyclic aromatic compounds. For instance, catalystssimilar to selective acetylene hydrogenation catalysts for ethyleneproduction while minimizing ethane formation are known and can be usedin the hydrodealkylation zone 30. In those known catalysts, Pd/aluminais typical; in the hydrodealkylation zone 30 Pd can be substituted byone or more other effective metal components as other one or combinationof metals as described herein, for instance, Mo, Co, Ir, Pd, Pt, Ni, W,Sn or Ga).

Suitable first functional catalysts generally contain one or more firstactive components of metals or metal compounds (oxides, carbides orsulfides), for instance a metal selected from the Periodic Table of theElements IUPAC Groups 6, 9, 10, 13 and/or 14, such as Mo, Co, Ir, Pd,Pt, Ni, Sn, W or Ga, and one or more second active components, forinstance a metal, metal compound, non-metal such as P, or othernon-metal compound. In certain embodiments two or more of the firstactive components mentioned above are used. One, two or more of theabove-mentioned active components are typically deposited or otherwiseincorporated on a catalyst support, which can be amorphous and/orstructured, such as silica-alumina, silica, titania, titania-silica,titania-silicates, zeolites (including HY, beta, mordenite, ZSM-5,ZSM-12, ZSM-22, ZSM-11, MCM-22, MCM-56, or SSZ-26/33 zeolites), orsimilar crystalline materials to zeolites such as SAPO. The catalystsupport(s) can be subjected to treatment whereby support properties suchas pore volume, surface area, and average pore size are altered, such asby meso-structuring treatments which include one or more ofdesilication, de-alumination, steaming, acid leaching, and templatedre-crystallization. In embodiments in which P is used, elemental form ofP can be added and treated with H₂SO₄, whereby after treatment P remainsin the structure of the catalyst. Combinations of active components canbe composed of different particles/granules containing a single activemetal species, or particles containing multiple active components. Inembodiments in which zeolites or other crystalline materials are used,they are conventionally formed with one or more binder components suchas alumina, silica, silica-alumina, clay, titania and mixtures thereof.In certain embodiments, the catalyst particles have a pore volume in therange of about (cc/gm) 0.15-1.70, 0.15-1.50, 0.30-1.50 or 0.30-1.70; aspecific surface area in the range of about (m²/g) 100-900, 100-500,100-450, 180-900, 180-500, 180-450, 200-900, 200-500 or 200-450; and anaverage pore diameter of at least about 30, 45 or 50, in certainembodiments in the range of about 30-80, 45-80, 50-80, 30-100, 45-100 or50-100, 30-200, 45-200 or 50-200 angstrom units. The active component(s)are incorporated in an effective concentration, for instance, in therange of (wt % based on the mass of the active component(s) relative tothe total mass of the catalysts including the support and binders) 1-40,1-30, 1-10, 1-5, 2-40, 2-30, 2-10, 3-40, 3-30 or 3-10. Effectivecatalysts to promote hydrogenation reactions include but are not limitedto those having one or more effective first active components, forinstance, Mo, Co, Ir, Pd, Pt, Ni, W, Sn or Ga, and optionally a secondactive components such as P, deposited or otherwise incorporated on asupport formed of alumina and/or zeolite. Examples include but are notlimited to MoP/zeolite (including HY zeolites), Pd/alumina (for instancecatalysts similar to selective acetylene hydrogenation catalysts forethylene production while minimizing ethane formation which are known),Pd/zeolite, MoP/alumina, NiP/alumina, NiP/zeolite, WP/alumina,WP/zeolite, or sulfided NiMo/alumina.

In certain embodiments, the first functional catalyst and/or thecatalyst support is prepared in accordance with U.S. Pat. No. 9,221,036and its continuation U.S. Pat. No. 10,081,009 (jointly owned by theowner of the present application, and subject to a joint researchagreement), which is incorporated herein by reference in its entirety.Such a support includes a modified zeolite support having one or more ofTi, Zr and/or Hf substituting the aluminum atoms constituting thezeolite framework thereof. For instance, the first functional catalysteffective for hydrogenation can include one or more active componentcarried on a support containing a framework-substituted zeolite such asa ultra-stable Y-type zeolite, in which a part of aluminum atomsconstituting a zeolite framework thereof is substituted one, two or allof Ti, Zr and Hf, for instance 0.1-5 mass % of each calculated on anoxide basis.

The second functional catalyst used in the hydrodealkylation zone 30 canbe one or more conventionally known, commercially available or futuredeveloped catalyst materials effective for selective ring opening andhydrodealkylation. The selection, activity and form of the selectivering opening and hydrodealkylation catalyst (the second functionalcatalyst) can be determined based on factors including but not limitedto operating conditions, selected reactor configuration, feedstockcomposition, and desired degree of conversion. Suitable secondfunctional catalysts contain one or more active components that aremetals or metal compounds (oxides, carbides or sulfides) selected fromthe Periodic Table of the Elements IUPAC Groups 6, 7, 8, 9 and 10, suchas Ni, W or Mo. In certain embodiments two or more of the activecomponents mentioned above are used. One, two or more of theabove-mentioned active components are typically deposited or otherwiseincorporated on a support, which can be amorphous and/or structured,such as silica-alumina, silica, titania, titania-silica,titania-silicates, zeolites (including HY, beta, mordenite, ZSM-5,ZSM-12, ZSM-22, ZSM-11, MCM-22, MCM-56, or SSZ-26/33 zeolites), orsimilar crystalline materials to zeolites such as SAPO. The catalystsupport(s) can be subjected to treatment whereby support properties suchas pore volume, surface area, and average pore size are altered, such asby meso-structuring treatments which include one or more ofdesilication, de-alumination, steaming, acid leaching, and templatedre-crystallization. Combinations of active components can be composed ofdifferent particles/granules containing a single active metal species,or particles containing multiple active components. In embodiments inwhich zeolites or other crystalline materials are used, they areconventionally formed with one or more binder components such asalumina, silica, silica-alumina, clay, titania and mixtures thereof. Incertain embodiments, the catalyst particles have a pore volume in therange of about (cc/gm) 0.15-1.70, 0.15-1.50, 0.30-1.50 or 0.30-1.70; aspecific surface area in the range of about (m²/g) 100-900, 100-500,100-450, 180-900, 180-500, 180-450, 200-900, 200-500 or 200-450; and anaverage pore diameter of at least about 30, 45 or 50, in certainembodiments in the range of about 30-80, 45-80, 50-80, 30-100, 45-100 or50-100, 30-200, 45-200 or 50-200 angstrom units. The active component(s)are incorporated in an effective concentration, for instance, in therange of (wt % based on the mass of the active component(s) relative tothe total mass of the catalysts including the support and binders) 1-40,1-30, 1-10, 1-5, 2-40, 2-30, 2-10, 3-40, 3-30 or 3-10. Effectivehydrocracking catalysts (second functional catalyst) include but are notlimited to one or more active components selected from the groupconsisting of Ni, W, Mo, deposited or otherwise incorporated on asupport formed of acidic alumina, silica alumina and/or zeolite.Examples include but are not limited to Ni/HY zeolite, Ni/alumina,W/alumina, Mo/zeolite, NiMo/alumina-USY zeolite, NiMo/silica alumina, orMoS₂/alumina.

In certain embodiments, the second functional catalyst and/or thecatalyst support is prepared in accordance with U.S. Pat. No. 9,221,036and its continuation U.S. Pat. No. 10,081,009 (jointly owned by theowner of the present application, and subject to a joint researchagreement), which is incorporated herein by reference in its entirety.Such a support includes a modified zeolite support having one or more ofTi, Zr and/or Hf substituting the aluminum atoms constituting thezeolite framework thereof. For instance, the second functional catalysteffective for hydrocracking can include one or more active componentcarried on a support containing a framework-substituted zeolite such asa ultra-stable Y-type zeolite, in which a part of aluminum atomsconstituting a zeolite framework thereof is substituted one, two or allof Ti, Zr and Hf, for instance 0.1-5 mass % of each calculated on anoxide basis.

A multi-functional catalyst used in the hydrodealkylation zone 30 can beone or more conventionally known, commercially available or futuredeveloped hydrogenation catalysts effective to maximize the both mainfunctions, that is, a first function of conversion of polyaromatics,such as naphthalene, methylnaphthalene, anthracene,naphtheno-diaromatics (three rings, one saturated and two aromatic), byselective hydrogenation into aromatic compounds with one benzene ring,and a second function of selective ring opening and hydrodealkylation.The selection, activity and form of the multi-functional catalyst can bedetermined based on factors including but not limited to operatingconditions, selected reactor configuration, feedstock composition, anddesired degree of conversion. The multi-functional catalyst generallyincludes first functional active components and second functional activecomponents. For example, suitable first functional active componentsinclude a) metals or metal compounds (oxides, carbides or sulfides), forinstance a metal selected from the Periodic Table of the Elements IUPACGroups 6, 9, 10, 13 and/or 14, such as Mo, Co, Ir, Pd, Pt, Ni, W, Sn orGa, and b) one or more second active components, for instance a metal,metal compound, non-metal such as P, or other non-metal compound.Suitable second functional active components are metals or metalcompounds (oxides, carbides or sulfides) selected from the PeriodicTable of the Elements IUPAC Groups 6, 7, 8, 9 and 10, such as NiMo orMoS₂.

One or more of each of the first and second functional active componentsof a multi-functional catalyst are typically deposited or otherwiseincorporated on a catalyst support, which can be amorphous and/orstructured, such as silica-alumina, silica, titania, titania-silica,titania-silicates, zeolites (including HY, beta, mordenite, ZSM-5,ZSM-12, ZSM-22, ZSM-11, MCM-22, MCM-56, or SSZ-26/33 zeolites), orsimilar crystalline materials to zeolites such as SAPO. The catalystsupport(s) can be subjected to treatment whereby support properties suchas pore volume, surface area, and average pore size are altered, such asby meso-structuring treatments which include one or more ofdesilication, de-alumination, steaming, acid leaching, and templatedre-crystallization. In embodiments in which P is used, elemental form ofP can be added and treated with H₂SO₄, whereby after treatment P remainsin the structure of the catalyst. Combinations of active components canbe composed of different particles/granules containing a single activemetal species, or particles containing multiple active components. Inembodiments in which zeolites or other crystalline materials are used,they are conventionally formed with one or more binder components suchas alumina, silica, silica-alumina, clay, titania and mixtures thereof.In certain embodiments, the multi-functional catalyst particles have apore volume in the range of about (cc/gm) 0.15-1.70, 0.15-1.50,0.30-1.50 or 0.30-1.70; a specific surface area in the range of about(m2/g) 100-900, 100-500, 100-450, 180-900, 180-500, 180-450, 200-900,200-500 or 200-450; and an average pore diameter of at least about 30,45 or 50, in certain embodiments in the range of about 30-80, 45-80,50-80, 30-100, 45-100 or 50-100, 30-200, 45-200 or 50-200 angstromunits. The active component(s) are incorporated in an effectiveconcentration, for instance, in the range of (wt % based on the mass ofthe active component(s) relative to the total mass of the catalystsincluding the support and binders) 1-40, 1-30, 1-10, 1-5, 2-40, 2-30,2-10, 3-40, 3-30 or 3-10. Effective multi-functional catalysts includebut are not limited to one or more first functional active componentsselected from a) Mo, Co, Ir, Pd, Pt, Ni, W, Sn or Ga, and b) a non-metalsuch as P, and one or more second functional components such as Ni, W,Mo, NiMo or MoS₂, deposited or otherwise incorporated on a supportformed of acidic alumina, silica alumina and/or zeolite. Examplesinclude but are not limited to NiP/zeolite, MoP/alumina or Pd—Ni/zeolite(including HY zeolites).

In certain embodiments, the multi-functional catalyst and/or thecatalyst support is prepared in accordance with U.S. Pat. No. 9,221,036and its continuation U.S. Pat. No. 10,081,009 (jointly owned by theowner of the present application, and subject to a joint researchagreement), which is incorporated herein by reference in its entirety.Such a support includes a modified zeolite support having one or more ofTi, Zr and/or Hf substituting the aluminum atoms constituting thezeolite framework thereof. For instance, the catalyst effective forhydrogenation can include one or more active component carried on asupport containing a framework-substituted zeolite such as aultra-stable Y-type zeolite, in which a part of aluminum atomsconstituting a zeolite framework thereof is substituted one, two or allof Ti, Zr and Hf, for instance 0.1-5 mass % of each calculated on anoxide basis.

The transalkylation zone 66 can contain one or more fixed bed, fluidizedbed, ebullated bed, slurry bed, moving bed, continuous stirred tank, ortubular reactors, in series or parallel arrangement, which is/aregenerally operated in the presence of hydrogen under conditions, andutilizes catalyst(s), effective for conversion of a portion of the C9stream from the BTX splitting zone 56 to xylenes. In certainembodiments, multiple reactors can be provided in parallel intransalkylation zone 66 to facilitate catalyst replacement and/orregeneration. The transalkylation zone 66 can also be in fluidcommunication with a source of toluene to react with C9 viatransalkylation reactions to produce additional xylenes. In certainembodiments toluene and benzene used to react with C9s can be from theBTX stream in the BTX splitting zone 56. In general, the transalkylationzone 66 includes an inlet in fluid communication with an outlet of theBTX splitting zone 56 discharging the C9 stream 62, which includestrimethyl-benzene, methylethylbenzene, and other C9 compounds. Thetransalkylation zone 66 also includes one or more outlets fordischarging product streams of BTX and C9+ aromatics, shown as stream 70and the light gases by-product including C₁-C₄ and hydrogen, stream 72.The transalkylation zone 66 is in fluid communication with a hydrogengas stream 68, which can be passed to the reactors at one or morelocations as is known, and can be derived from sources includingrecycled hydrogen from the integrated steam cracking unit (not shown),produced hydrogen 76 from the gas treatment zone 74, and hydrogen 90from the reforming zone 80. Make-up hydrogen from another source (notshown) is also typically added.

The transalkylation zone 66 includes an effective reactor configurationwith the requisite reaction vessel(s), feed heaters, heat exchangers,hot and/or cold separators, product fractionators, strippers, and/orother units to process the C9 stream from the BTX splitting zone 56. Thetransalkylation zone 66 operates in the presence of hydrogen, stream 68,under conditions effective to, and using catalyst effective to, maximizethe transalkylation of unconverted trimethyl-benzene C9 aromatics andtoluene to produce xylenes. The transalkylation zone 66 can also beconfigured to perform isomerization of mixed xylenes to promoteproduction of para-xylene. The light gases stream 72 (which in certainembodiments can contain naphtha-range byproducts such as light naphtha)is in fluid communication with the gas treatment zone 74 for recovery ofhydrogen and recovery of LPG and optionally naphtha-range components asadditional feed to the steam cracking zone.

The C9 stream from the BTX splitting zone 56 and a hydrogen stream 68are charged to the reactor of the transalkylation zone 66. The hydrogenstream contains an effective quantity of hydrogen to support the mixedxylene production from the feed, the reaction conditions, the selectedcatalysts and other factors, and can be any combination includinghydrogen derived from the hydrogen producers within the integratedsystem and process, stream 76, and in certain embodiments 90, and incertain embodiments make-up hydrogen from another source.

Mixed xylenes that form part of the transalkylation reaction effluentstream 70 include the less commercially valuable m-xylene forms ingreater amounts than either p- or o-xylenes because of thermodynamicequilibrium relationships between the three isomers. In certainembodiments separation of p-xylene is desired, for instance when marketdemand favors p-xylene over o-xylene and m-xylene. In some embodiments,the transalkylation reaction zone can also include an isomerizationreactor to isomerize para-xylene-free mixed xylenes received from apara-xylene separator to reestablish the thermodynamic equilibrium of C8aromatics (that is, xylene isomers) para-xylene. A para-xylene separatorcan separate and produce product streams of para-xylene andpara-xylene-free mixed xylenes (that is, ortho- and meta-xylenes) fromthe transalkylation reaction effluent. In some embodiments, thepara-xylene separator can be an adsorptive process or a crystallizationprocess. In some embodiments, the para-xylene-free mixed xylenes streamproduced by the para-xylene separator can be provided to thetransalkylation reaction zone 66 for reestablishing a C8 aromaticsthermodynamic equilibrium of xylene isomers and promoting formation ofadditional para-xylene.

Reaction conditions are set to maximize the conversion of the C9 streamfrom the BTX splitting zone 56 to xylenes by transalkylation reactions.In general, the operating conditions for the reactor of a suitabletransalkylation reaction zone 66 include:

-   -   a reaction temperature (° C.) of from about 300-450, 300-420,        320-450 or 320-420;    -   an operating pressure (hydrogen partial pressure, kg/cm′) of        from about 5-30, 5-25, 5-20, 10-30, 10-25 or 10-20;    -   a hydrogen feed rate (SL/L) of from about 1-10, 1-8, 2-10 or        2-8; and    -   a feed rate (liquid hourly space velocity, h⁻¹) of from about        1-10, 1-8, 2-10 or 2-8.

The catalyst used in the transalkylation zone 66 can be one or moreconventionally known, commercially available or future developedtransalkylation catalyst zone 66 are effective to maximize selectiveconversion of trimethyl-benzene and toluene into mixed xylenes. Incertain embodiments the catalyst used in the transalkylation zone 66 arecapable of converting a significant portion and, in some embodiments,all, of the trimethyl-benzene in the C9 aromatics stream to mixedxylenes under effective operating conditions. An appropriate,commercially available transalkylation catalyst can be used. Theselection, activity and form of the transalkylation catalyst can bedetermined based on factors including but not limited to operatingconditions, selected reactor configuration, feedstock composition,ratios of toluene to trimethyl-benzene, and desired degree ofconversion. For example, suitable catalysts generally contain one ormore active components selected from the group consisting of silicon,phosphorus, boron, magnesium, tin, titanium, zirconium, molybdenum,germanium, indium, lanthanum, cesium, and any oxide thereof. The activecomponent is typically deposited or otherwise incorporated on a supportsuch as a beta zeolite support catalyst support, which can be a zeolitematerial such as USY zeolite, NaHY zeolite, ZSM-12 zeolite, mesoporoussurface area (MSA) zeolite, Al₂O₃ zeolite, beta zeolite, mordenitezeolite or silicate-1 zeolite.

The catalytic reforming zone 80 treats naphtha, typically hydrotreatednaphtha, to produce a reformate stream 84. A schematic process flowdiagram of a catalytic reforming zone 80 is shown in FIG. 7, and incertain embodiments combined with the units of FIG. 8. The catalyticreforming zone 80 can include a naphtha hydrotreating zone, and thecatalytic reforming reaction zone. In certain embodiments the catalyticreforming zone also includes a reformate splitter and/or a benzenesaturation unit. Product from the naphtha hydrotreating zone includesLPG and gases, and a hydrotreated naphtha product that is routed to anaphtha reformer. The naphtha reformer converts hydrotreated naphtha toreformate stream 84 that is passed to the BTX splitting zone 56. Incertain embodiments, all or a portion of the reformate stream 84 can beused in a conventional manner, that is, as gasoline blending components.

The source of naphtha feed 82 can be from one or more of: naphtha-rangecomponents produced in one or more operations of the integrated processherein including the hydrodealkylation zone 30; naphtha from the initialfeed 120 (which initial feed 120 can be crude oil) after a separatorsection (such as a distillation column) to separate the initial feedinto three streams, a naphtha stream, a lighter than naphtha stream(boiling point<naphtha) and a heavier than naphtha stream (boilingpoint>naphtha), where the naphtha is all or part of stream 82 and theother streams can serve as the initial feed as described herein; and/ora sourced naphtha stream such as naphtha (straight run, treated or wildnaphtha) obtained from outside of the refinery limits.

The reactions involved in catalytic reforming include hydrocracking,dehydrocyclization, dehydrogenation, isomerization, and to a lesserextent, demethylation and dealkylation. A particular hydrocarbon/naphthafeed molecule may undergo more than one category of reaction and/or mayform more than one product. The hydrocarbon/naphtha feed composition,the impurities present therein, and the desired products will determinesuch process parameters as choice of catalyst(s), process type, and thelike.

The reaction rate for conversion of naphthenes to aromatics favors lowpressure, but such low pressure operations also promotes coke formationwhich deactivates the catalyst. Thus, with lower operating pressure thearomatics yield increases, but catalyst regeneration must occur morefrequently. To maintain the desired lower operating pressure and alsoaddress coke formation, different methodologies are known. The generaltypes of catalytic reforming process configurations differ in the mannerin which the reforming catalyst is regenerated for removal of cokeformed during reaction. Catalyst regeneration, which involves combustingthe detrimental coke in the presence of oxygen, includes asemi-regenerative process, cyclic regeneration and continuous catalystregeneration (CCR). Semi-regeneration is the simplest configuration, andthe entire unit, including all reactors in the series is shutdown forcatalyst regeneration in all reactors. Cyclic configurations utilize anadditional “swing” reactor to permit one reactor at a time to be takenoff-line for regeneration while the others remain in service. Continuouscatalyst regeneration configurations, which are the most complex,provide for essentially uninterrupted operation by catalyst removal,regeneration and replacement. While continuous catalyst regenerationconfigurations include the ability to increase the severity of theoperating conditions due to higher catalyst activity, the associatedcapital investment is necessarily higher.

Referring to FIG. 7, a reforming zone 80 includes a naphthahydrotreating zone 168 integrated with a catalytic reforming reactionzone 170 for the processing of a naphtha stream 82, to produce reformatestream 84 for aromatics recovery via the BTX splitting zone 56. Incertain embodiments or in certain modes of operation, all or a portionof the reformate stream 84 can be used as a gasoline blend component. Incertain embodiments, all, a substantial portion, a significant portionor a major portion of the reformate stream 84 is passed to the BTXsplitting zone 56, and any remainder can be blended in a gasoline pool.

Naphtha hydrotreating occurs in the presence of an effective amount ofhydrogen obtained from recycle within the naphtha hydrotreating zone 168(not shown), recycle reformer hydrogen 172, and if necessary make-uphydrogen (not shown). A gas stream of effluent off-gases and LPG, stream182, is recovered from the naphtha hydrotreating zone 168 and can bepassed to the gas treatment zone 74, for instance as part of the stream88, and/or can be integrated directly to a fuel gas system. In certainembodiments LPG is separately recovered from the naphtha hydrotreatingzone 168 and is routed to the steam cracking zone 10.

The naphtha hydrotreating zone 168 is operated in the presence ofhydrogen under conditions, and utilizes catalyst(s), effective forremoval of a significant amount of the sulfur and other knowncontaminants. Accordingly, the naphtha hydrotreating zone 168 subjectsfeed to hydrotreating conditions to produce a hydrotreated straight runnaphtha stream 174 effective as feed to the catalytic reforming reactionzone 170. As is known, the naphtha hydrotreating zone 168 operates withsuitable catalysts and under conditions (temperature, pressure, hydrogenpartial pressure, liquid hourly space velocity (LHSV), catalyst loading)that are effective to remove at least enough sulfur, nitrogen, olefinsand other contaminants needed to meet requisite product specifications.Hydrotreating in conventional naphtha reforming systems generally occursunder relatively mild conditions that are effective to remove sulfur andnitrogen to requisite levels for catalytic reforming, for instance lessthan 0.5 ppmw of sulfur and nitrogen.

The hydrotreated naphtha stream 174 is passed to a catalytic reformingreaction zone 170. In certain embodiments, all, a substantial portion ora significant portion of the hydrotreated naphtha stream 174 is passedto the catalytic reforming reaction zone 170, and any remainder can beblended in a gasoline pool. As is known, the catalytic reformingreaction zone 170 operates with suitable catalysts and under conditions(temperature, pressure, LHSV, hydrogen to hydrocarbon molar ratio,catalyst loading) that are effective to carry out the desired degree ofnaphtha reforming. In general, the operating conditions for thecatalytic reforming reaction zone 170 include:

-   -   a reaction temperature (° C.) of from about 400-560, 450-560,        400-530 or 450-530;    -   a hydrogen partial pressure (kg/cm²) of from about 1-50, 1-40,        3-50 or 3-49; and    -   a feed rate (liquid hourly space velocity, h⁻¹) of from about        0.5-10, 0.5-5, 0.5-3, 1-10, 1-5 or 1-3.

In the catalytic reforming process, paraffins and naphthenes arerestructured to produce isomerized paraffins and aromatics of relativelyhigher octane numbers. The catalytic reforming converts low octanen-paraffins to i-paraffins and naphthenes. Naphthenes are converted tohigher octane aromatics. The aromatics are left essentially unchanged orsome may be hydrogenated to form naphthenes due to reverse reactionstaking place in the presence of hydrogen.

A reactor effluent 176, containing hot reformate and hydrogen, is cooledand passed to separator 178 for recovery of hydrogen stream 180 and aseparator bottoms stream 184. The hydrogen stream 180 is split into aportion 182 which is compressed and recycled back to the reformerreactors, and in certain embodiments into the excess hydrogen stream 90.The separator bottoms stream 184 is passed to a stabilizer column 186 toproduce the light end stream 88 and the reformate stream 84. The lightend stream 88 is recovered and can be routed to the steam cracking zone10 and/or gas treatment zone 74 as described herein.

The net hydrogen stream 90 can be recovered from the reforming zone 80,which comprises excess hydrogen passed to other hydrogen usersincluding: those within the catalytic reforming zone 80 such as thenaphtha hydrotreating zone 168 and in certain embodiments a benzenesaturation unit 204 shown in FIG. 9; and/or other to hydrogen users inthe integrated process and system.

Referring to FIG. 8, another embodiment of a catalytic reforming zone 80is schematically depicted. A series of reactors 170 are provided. Afeedstock, hydrotreated naphtha 174, is heat exchanged via exchanger 188with a hot reformate stream 176 to increase the temperature of the feed.The heated feedstock is treated in a series of reaction zones containingreformer reactors 170, shown in the exemplary embodiment as zones A-D,although fewer or more zones can be used. The hot reformate stream 176contains hot product hydrogen and reformate. The reforming reactions areendothermic resulting in the cooling of reactants and products,requiring heating of effluent, typically by direct-fired furnaces 192,prior to charging as feed to a subsequent reforming reactor 170. As aresult of the very high reaction temperatures, catalyst particles aredeactivated by the formation of coke on the catalyst which reduces theavailable surface area and active sites for contacting the reactants.Hot product hydrogen and reformate stream 176 passes through the heatexchanger and then to separator 178 for recovery of hydrogen stream 180and a separator bottoms stream 184. Recovered hydrogen stream 180 issplit with a portion 182 compressed and recycled back to the reformerreactors, and excess hydrogen 90 is recovered. The separator bottomsstream 184 is sent to a stabilizer column 186 to produce the light endstream 88 and a reformate stream 84.

In certain optional embodiments, and with reference to FIG. 9, toincrease production of gasoline fuel components, the reformate stream ispassed to separation and hydrogenation steps to reduce the total benzenecontent. For instance, instead of passing all or a portion of the totalreformate stream 84 to the BTX splitting zone 56, all or a portion canbe passed to a reformate splitter 194 and separated into one or morerelatively benzene-rich fractions 196 and one or more relativelybenzene-lean fractions 198 and 202. Typically, the relativelybenzene-rich middle fraction 196, known as a “benzene heart cut,”comprises about 10-20 vol % of the total reformate and contains about20-30 vol % benzene. In contrast, the relatively benzene-lean heavyreformate bottom fraction 202 comprises about 40-80 V % of the totalreformate and has a benzene content generally in the range of from about0.3-1 vol %. The light reformate top fraction 198 which includes about10-25 vol % of the total reformate, contains about 5-30 vol % benzeneand is recovered or blended with other product pools.

The heart cut fraction 196, which contains a majority of the benzenecontent of total reformate stream 84, can be passed to a hydrogenationunit 204, also referred to as a benzene saturation unit, or directly tothe BTX splitting zone 56. Hydrogenation reactions occur in the presenceof a predetermined amount of hydrogen gas 206 for conversion reactionsincluding conversion of benzene to cyclohexane, and for the productionof a benzene-lean and in certain embodiments an essentiallybenzene-free, gasoline blending component 208. The benzene saturationunit typically contains an effective quantity of catalyst having asuitable level of active materials possessing hydrogenationfunctionality, including but not limited to a metal selected from thePeriodic Table of the Elements IUPAC Groups 9 or 10, such as nickel,platinum, supported on an alumina substrate.

All or a portion of the benzene-lean blending component 208 can be mixedwith the remaining gasoline pool constituents including the benzene-leanheavy reformate bottom fraction 202. For instance, when blended with theheavy reformate fraction 202 which can contain up to 1 vol % benzene, afinal gasoline product can be recovered which contains less than about 1vol % benzene. Further, all or a portion of benzene-lean blendingcomponent 208 can be routed to the steam cracking zone 10. All of aportion of the light benzene lean fraction 198 can be routed to agasoline pool or to the steam cracking zone 10. All or a portion of theheavy benzene lean fraction 202 can be routed to the BTX splitting zone56 or to the steam cracking zone 10, or passed to a gasoline pool 210without further processing.

The method and system of the present invention have been described aboveand in the attached drawings; however, modifications will be apparent tothose of ordinary skill in the art and the scope of protection for theinvention is to be defined by the claims that follow.

1. A process for treatment of PFO from a steam cracking zone thatproduces light olefins and PFO from a steam cracking feed, the processcomprising: optionally separating the PFO into at least a first streamcontaining C9+ aromatics compounds with one benzene ring and C10+aromatic compounds, and a second stream containing C20+ polyaromaticcompounds; reacting all or a portion of the PFO, or all or a portion ofthe first stream containing C9+ aromatics compounds with one benzenering and C10+ aromatic compounds, using catalysts and conditions,including hydrogen, effective for conversion of polyaromatics compoundscontained in the PFO into aromatic compounds with one benzene ring,selective ring opening, and dealkylation, to produce reaction effluentincluding LPG and a hydrodealkylated BTX+ stream; separating LPG fromthe reaction effluent; subjecting a naphtha feed to catalytic reformingto produce a reformate stream; and separating at least a portion of thereformate stream and at least a portion of the hydrodealkylated BTX+stream into BTX compounds.
 2. The process as in claim 1, wherein the PFOis obtained from steam cracking of treated crude oil or other treatedheavy oil feeds, and comprises at least 40 wt % of polyaromatics havingthree or more aromatic rings including triaromatics,naphtheno-triaromatics, tetraaromatics, penta-aromatics and heavierpoly-aromatics including asphaltenes and coke.
 3. The process as inclaim 1, wherein all or a portion of the C20+ polyaromatic compounds areseparated as the second stream prior to reacting all or a portion of thefirst stream to produce the hydrodealkylated BTX+ stream.
 4. The processas in claim 1, wherein the PFO stream or the second stream contains C20+polyaromatic compounds, and wherein: reacting occurs in the presence ofcatalyst, and wherein reaction conditions to produce a hydrodealkylatedBTX+ stream comprise a reaction temperature (° C.) in the range of about300-550, a reaction pressure (hydrogen partial pressure, kg/cm²) in therange of about 3-30, a hydrogen feed rate (standard liters per liter ofhydrocarbon feed, SLt/Lt) in the range of about 1-30, and a LHSV in therange of about 0.1-10.
 5. The process as in claim 1, wherein all or aportion of C20+ polyaromatic compounds are removed prior to selectivehydrogenation, and wherein: reacting occurs in the presence of catalyst,and wherein reaction conditions to produce a hydrodealkylated BTX+stream comprise a reaction temperature (° C.) in the range of about300-500, a reaction pressure (hydrogen partial pressure, kg/cm²) in therange of about 3-25, a hydrogen feed rate (standard liters per liter ofhydrocarbon feed, SLt/Lt) in the range of about 1-25, and a LHSV in therange of about 0.1-8.
 6. The process as in claim 1, wherein theseparated LPG stream is treated and passed to the steam cracking zone.7. The process as in claim 1, wherein separating at least a portion ofthe hydrodealkylated BTX+ stream into BTX compounds further comprisesseparating C9 aromatic compounds, and wherein the process furthercomprises transalkylating the separated C9 aromatic compounds to producea transalkylated effluent containing additional BTX compounds.
 8. Theprocess as in claim 7, wherein light gases from transalkylating aretreated and one or more LPG streams are recovered, and wherein the oneor more LPG streams are passed to the steam cracking zone as additionalsteam cracking feed.
 9. The process as in claim 7, further comprisingseparating naphtha-range hydrocarbon compounds from the transalkylatedeffluent prior to separation into BTX compounds, and passing all or aportion of said naphtha-range hydrocarbon compounds to the steamcracking zone as additional steam cracking feed, or wherein all or aportion of said naphtha-range hydrocarbon compounds comprise at least aportion of the naphtha feed to catalytic reforming.
 10. The process asin claim 7, further comprising recovering a raffinate stream comprisingnon-aromatic compounds from the transalkylated effluent, and passing allor a portion of said raffinate stream to the steam cracking zone asadditional steam cracking feed.
 11. The process as in claim 10, whereinrecovering a raffinate stream is by aromatics extraction to separate thehydrodealkylated BTX+ stream into the raffinate stream and an extractstream comprising aromatic compounds, and wherein the extract stream isseparated into the BTX compounds.
 12. The process as in claim 1, whereinseparating the hydrodealkylated BTX+ stream into BTX compounds furthercomprises separating C10+ compounds from the hydrodealkylated BTX+stream.
 13. The process as in claim 12, wherein at least a portion ofthe separated C10+ compounds are subjected to reactions to produce thehydrodealkylated BTX+ stream.
 14. The process as in claim 12, wherein aninitial feed is subjected to treatment upstream of the steam crackingzone, and wherein at least a portion of the separated C10+ compounds aresubjected to treatment with the initial feed.
 15. The process as inclaim 1, further comprising separating naphtha-range hydrocarboncompounds from the hydrodealkylated BTX+ stream prior to separation intoBTX compounds, and passing all or a portion of said naphtha-rangehydrocarbon compounds to the steam cracking zone as additional steamcracking feed.
 16. The process as in claim 1, further comprisingseparating naphtha-range hydrocarbon compounds from the hydrodealkylatedBTX+ stream prior to separation into BTX compounds, wherein all or aportion of said naphtha-range hydrocarbon compounds comprise at least aportion of the naphtha feed to catalytic reforming.
 17. The process asin claim 1, further comprising separating at least a portion of thehydrodealkylated BTX+ stream into BTX compounds includes recovering araffinate stream comprising non-aromatic compounds, and passing all or aportion of said raffinate stream to the steam cracking zone asadditional steam cracking feed.
 18. The process as in claim 17, whereinrecovering a raffinate stream is by aromatics extraction to separate thehydrodealkylated BTX+ stream into the raffinate stream and an extractstream comprising aromatic compounds, and wherein the extract stream isseparated into the BTX compounds.
 19. The process as in claim 1, furthercomprising separating at least a portion of the reformate stream intoBTX compounds includes recovering a raffinate stream comprisingnon-aromatic compounds, and passing all or a portion of said raffinatestream to the steam cracking zone as additional steam cracking feed. 20.The process as in claim 19, wherein recovering a raffinate stream is byaromatics extraction to separate the reformate stream into the raffinatestream and an extract stream comprising aromatic compounds, and whereinthe extract stream is separated into the BTX compounds.
 21. A steamcracking process comprising steam cracking a steam cracker feed toproduce olefins, pyrolysis gasoline and PFO; and treating the PFO as inthe process of claim
 1. 22. A system for treatment of PFO from a steamcracking zone that produces at least light olefins and PFO from a steamcracking feed, the system comprising: an optional PFO separation zonehaving one or more inlets in fluid communication with the steam crackingzone, one or more outlets for discharging a fraction of the PFOincluding C9+ aromatics compounds with one benzene ring and C10+aromatic compounds, and one or more outlets for discharging a fractionof the PFO including containing C20+ polyaromatic compounds; ahydrodealkylation zone having one or more inlets in fluid communicationwith the steam cracking zone to receive PFO or the first outlet of thePFO separation zone to receive C9+ aromatics compounds with one benzenering and C10+ aromatic compounds from the PFO, and hydrogen, and one ormore outlets for discharging reaction effluent including LPG andhydrodealkylated BTX+ compounds; a separation zone having one or moreinlets in fluid communication with the one or more outlets of thehydrodealkylation zone, one or more outlets for discharging LPG, and oneor more outlets for discharging hydrodealkylated BTX+ compounds; acatalytic reforming zone having one or more inlets in fluidcommunication with a source of naphtha feed and one or more outlets fordischarging a reformate stream; and a BTX splitting zone having one ormore inlets in fluid communication with the one or more outlets of theseparation zone for discharging hydrodealkylated BTX+ compounds, andwith the one or more outlets of the catalytic reforming zone fordischarging a reformate stream, and one or more outlets for dischargingBTX compounds.
 23. The system as in claim 22, comprising the PFOseparation zone. 24-36. (canceled)